Management Report

          The consolidated  financial statements were prepared by the management
of  FirstEnergy  Corp.,  who  takes   responsibility  for  their  integrity  and
objectivity.   The  statements  were  prepared  in  conformity  with  accounting
principles generally accepted in the United States and are consistent with other
financial  information  appearing elsewhere in this report. Arthur Andersen LLP,
independent  public  accountants,  have expressed an unqualified  opinion on the
Company's consolidated financial statements.

          The Company's  internal  auditors,  who are  responsible  to the Audit
Committee  of the Board of  Directors,  review the  results and  performance  of
operating units within the Company for adequacy,  effectiveness  and reliability
of  accounting  and  reporting  systems,  as well as  managerial  and  operating
controls.

          The Audit Committee consists of six nonemployee directors whose duties
include:  consideration of the adequacy of the internal  controls of the Company
and the  objectivity of financial  reporting;  inquiry into the number,  extent,
adequacy and  validity of regular and special  audits  conducted by  independent
public  accountants and the internal  auditors;  recommendation  to the Board of
Directors  of  independent  accountants  to conduct the normal  annual audit and
special  purpose  audits  as may be  required;  and  reporting  to the  Board of
Directors the Committee's  findings and any recommendation for changes in scope,
methods or procedures of the auditing functions.  The Committee also reviews the
results of  management's  programs  to  monitor  compliance  with the  Company's
policies on business ethics and risk  management.  The Audit Committee held four
meetings in 2001.



Richard H. Marsh
Senior Vice President
and Chief Financial Officer


Harvey L. Wagner
Vice President, Controller
and Chief Accounting Officer



<PAGE>


Report of Independent Public Accountants

To the Stockholders and Board of Directors of FirstEnergy Corp.:

          We have  audited  the  accompanying  consolidated  balance  sheets and
consolidated   statements  of  capitalization  of  FirstEnergy  Corp.  (an  Ohio
corporation)  and subsidiaries as of December 31, 2001 and 2000, and the related
consolidated statements of income, common stockholders' equity, preferred stock,
cash flows and taxes for each of the three  years in the period  ended  December
31, 2001.  These financial  statements are the  responsibility  of the Company's
management.  Our  responsibility  is to express  an  opinion on these  financial
statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted
          in the United States. Those standards require that we plan and perform
the audit to obtain reasonable  assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements.  An
audit also includes  assessing the accounting  principles  used and  significant
estimates  made by  management,  as well as  evaluating  the  overall  financial
statement  presentation.  We believe that our audits provide a reasonable  basis
for our opinion.

          In our opinion,  the  financial  statements  referred to above present
fairly, in all material  respects,  the financial  position of FirstEnergy Corp.
and  subsidiaries  as of December  31,  2001 and 2000,  and the results of their
operations  and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting  principles  generally accepted
in the United States.

          As  explained  in  Note 1 to the  consolidated  financial  statements,
effective  January 1, 2001,  the Company  changed its method of  accounting  for
derivative instruments and hedging activities by adopting Statement of Financial
Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging
Activities", as amended.





ARTHUR ANDERSEN LLP


Cleveland, Ohio,
   March 18, 2002.




<PAGE>
<TABLE>
<CAPTION>



                                                          FIRSTENERGY CORP.

                                                       SELECTED FINANCIAL DATA

For the Years Ended December 31,                       2001           2000          1999          1998          1997
-------------------------------------------------------------------------------------------------------------------------
                                                                 (In thousands, except per share amounts)

<S>                                               <C>            <C>            <C>            <C>           <C>
Revenues.......................................   $ 7,999,362    $ 7,028,961    $ 6,319,647    $ 5,874,906   $ 2,961,125
                                                  -----------------------------------------------------------------------
Income Before Extraordinary Item and
   Cumulative Effect of Accounting Change......   $   654,946    $   598,970    $   568,299    $   441,396   $   305,774
                                                  -----------------------------------------------------------------------
Net Income.....................................   $   646,447    $   598,970    $   568,299    $   410,874   $   305,774
                                                  -----------------------------------------------------------------------
Basic Earnings per Share of Common Stock:
   Before Extraordinary Item and Cumulative
     Effect of Accounting Change                        $2.85          $2.69          $2.50          $1.95         $1.94
   After Extraordinary Item and Cumulative
     Effect of Accounting Change...............         $2.82          $2.69          $2.50          $1.82         $1.94
                                                  -----------------------------------------------------------------------
Diluted Earnings per Share of Common Stock:
   Before Extraordinary Item and Cumulative
     Effect of Accounting Change...............         $2.84          $2.69          $2.50          $1.95         $1.94
   After Extraordinary Item and Cumulative
     Effect of Accounting Change...............         $2.81          $2.69          $2.50          $1.82         $1.94
                                                  -----------------------------------------------------------------------
Dividends Declared per Share of Common Stock...         $1.50          $1.50          $1.50          $1.50         $1.50
                                                  -----------------------------------------------------------------------
Total Assets...................................   $37,351,513    $17,941,294    $18,224,047    $18,192,177   $18,261,481
                                                  -----------------------------------------------------------------------
Capitalization at December 31:
   Common Stockholders' Equity.................   $ 7,398,599    $ 4,653,126    $ 4,563,890    $ 4,449,158   $ 4,159,598
   Preferred Stock:
     Not Subject to Mandatory Redemption.......       480,194        648,395        648,395        660,195       660,195
     Subject to Mandatory Redemption...........       594,856        161,105        256,246        294,710       334,864
   Long-Term Debt*.............................    12,865,352      5,742,048      6,001,264      6,352,359     6,969,835
                                                  -----------------------------------------------------------------------
     Total Capitalization*.....................   $21,339,001    $11,204,674    $11,469,795    $11,756,422   $12,124,492
                                                  =======================================================================
<FN>

  * 2001 includes approximately $1.4 billion of long-term debt (excluding
    long-term debt due to be repaid within one year) included in "Liabilities
    Related to Assets Pending Sale" on the Consolidated Balance Sheet as of
    December 31, 2001.

</FN>
</TABLE>

                 PRICE RANGE OF COMMON STOCK

         The  Common  Stock of  FirstEnergy  Corp.  is  listed on the New York
Stock  Exchange  and is  traded  on other  registered exchanges.

                                        2001                     2000
----------------------------------------------------------------------------
First Quarter High-Low.......    $31.75     $25.10          $23.56   $18.00
Second Quarter High-Low......     32.20      26.80           26.88    20.56
Third Quarter High-Low.......     36.28      29.60           27.88    22.94
Fourth Quarter High-Low......     36.98      32.85           32.13    24.11
Yearly High-Low..............     36.98      25.10           32.13    18.00
----------------------------------------------------------------------------

Prices are based on reports published in The Wall Street Journal for New York
                                         -----------------------
Stock Exchange Composite Transactions.



                             HOLDERS OF COMMON STOCK

There were 173,121 and 172,285 holders of 297,636,276 shares of FirstEnergy's
Common Stock as of December 31, 2001 and January 31, 2002, respectively.
Information regarding retained earnings available for payment of cash dividends
is given in Note 4A.


<PAGE>


                                FIRSTENERGY CORP.

                     Management's Discussion and Analysis of
                  Results of Operations and Financial Condition


          This  discussion   includes   forward-looking   statements   based  on
information  currently  available to management that is subject to certain risks
and uncertainties.  Such statements  typically contain,  but are not limited to,
the terms anticipate,  potential,  expect, believe,  estimate and similar words.
Actual  results may differ  materially  due to the speed and nature of increased
competition  and  deregulation  in the electric  utility  industry,  economic or
weather  conditions  affecting future sales and margins,  changes in markets for
energy services,  changing energy and commodity  market prices,  legislative and
regulatory   changes  (including  revised   environmental   requirements),   the
availability  and  cost  of  capital,  our  ability  to  accomplish  or  realize
anticipated benefits from strategic initiatives and other similar factors.

          FirstEnergy  Corp. is a holding  company that  provides  regulated and
competitive  energy  services  (see Results of  Operations - Business  Segments)
domestically and internationally.  The international operations were acquired as
part of  FirstEnergy's  acquisition  of GPU, Inc. in November 2001. GPU Capital,
Inc. and its  subsidiaries  provide  electric  distribution  services in foreign
countries.  GPU  Power,  Inc.  and its  subsidiaries  develop,  own and  operate
generation  facilities in foreign  countries.  Sales are pending for portions of
the international operations (see Capital Resources and Liquidity). Prior to the
GPU merger,  regulated electric  distribution services were provided to portions
of Ohio and Pennsylvania by our wholly owned  subsidiaries - Ohio Edison Company
(OE), The Cleveland  Electric  Illuminating  Company (CEI),  Pennsylvania  Power
Company  (Penn) and The Toledo Edison  Company (TE) with  American  Transmission
Systems, Inc. (ATSI) providing transmission services.  Following the GPU merger,
regulated  services are also provided through wholly owned subsidiaries - Jersey
Central Power & Light Company (JCP&L),  Metropolitan Edison Company (Met-Ed) and
Pennsylvania  Electric Company  (Penelec) - which provide electric  distribution
and  transmission  services  to  portions of  Pennsylvania  and New Jersey.  The
coordinated  delivery  of energy and  energy-related  products to  customers  in
unregulated  markets is provided through a number of  subsidiaries,  often under
master   contracts   providing   for  the   delivery  of  multiple   energy  and
energy-related  services.  Prior to the GPU merger,  competitive  services  were
principally   provided  by  FirstEnergy   Solutions  Corp.  (FES),   FirstEnergy
Facilities Services Group, LLC (FEFSG) and MARBEL Energy Corporation.  Following
the GPU merger,  competitive  services  are also  provided  through GPU Advanced
Resources, Inc. and MYR Group, Inc.

GPU Merger

          On  November  7,  2001,  the  merger  of  FirstEnergy  and GPU  became
effective with FirstEnergy being the surviving company. The merger was accounted
for using  purchase  accounting  under the  guidelines of Statement of Financial
Accounting  Standards No. (SFAS) 141,  "Business  Combinations."  Under purchase
accounting,  the results of operations for the combined entity are reported from
the  point  of  consummation  forward.  As  a  result,  FirstEnergy's  financial
statements  for 2001  reflect  twelve  months of  operations  for  FirstEnergy's
pre-merger  organization and only seven weeks of operations (November 7, 2001 to
December 31, 2001) for the former GPU companies.  Additional  goodwill resulting
from the merger ($2.3  billion) plus goodwill  existing at GPU ($1.9 billion) at
the time of the merger is not being  amortized,  reflecting  the  application of
SFAS 142,  "Goodwill  and Other  Intangible  Assets."  Goodwill  continues to be
subject to review for  potential  impairment  (see  Recently  Issued  Accounting
Standards).  Prior to consummation  of the GPU merger we identified  certain GPU
international  operations (see Note 2 -  Divestitures-International  Operations)
providing gas  transmission and electric  distribution  services for divestiture
within twelve months of the merger date. These operations  constitute individual
"lines of business" as defined in Accounting  Principles Board Opinion (APB) No.
30,  "Reporting the Results of Operations - Reporting the Effects of Disposal of
a Segment of a Business,  and Extraordinary,  Unusual and Infrequently Occurring
Events and Transactions" with physically and operationally separable activities.
Application of Emerging Issues Task Force (EITF) Issue No. 87-11, "Allocation of
Purchase  Price to Assets to Be Sold,"  requires  that  expected,  pre-sale cash
flows  (including  incremental  interest costs on related  acquisition  debt) of
these   operations  be  considered  part  of  the  purchase  price   allocation.
Accordingly,  subsequent to the merger date,  results of operations (and related
interest expense) of these international  subsidiaries have not been included in
FirstEnergy's  Consolidated  Statement  of  Income.  Additionally,   assets  and
liabilities  of  these  international  operations  have  been  segregated  under
separate  captions - "Assets  Pending Sale" and  "Liabilities  Related to Assets
Pending Sale" on FirstEnergy's Consolidated Balance Sheet.

Results of Operations

          Net income  increased  to $646.4  million in 2001,  compared to $599.0
million in 2000 and  $568.3  million in 1999.  Net  income in 2001  included  an
after-tax  charge of $8.5 million  resulting  from the  cumulative  effect of an
accounting  change due to the adoption of SFAS 133,  "Accounting  for Derivative
Instruments and Hedging Activities." Excluding the seven weeks of the former GPU
companies'  results (and related  interest  expense on  acquisition  debt),  net
income  increased  to $613.7  million  in 2001 due to reduced  depreciation  and
amortization, general taxes and net interest

<PAGE>



charges.  The  benefit of these  reductions  was offset in part by lower  retail
electric  sales,  increased  other  operating  expenses and higher gas costs. In
2000, lower fuel costs, increased generation output, reduced financing costs and
gains realized on the sale of emission allowances contributed to the increase in
net income from the prior year.

          Total  revenues  increased  $970.4  million in 2001  compared to 2000.
Excluding  the seven  weeks of  results  from the former  GPU  companies,  total
revenues  increased $336.7 million  following a $709.3 million increase in 2000.
In both 2001 and 2000,  the  additional  sales resulted from an expansion of our
unregulated  businesses,  which more than offset  lower sales from our  electric
utility  operating  companies  (EUOC).  Sources  of changes  in  pre-merger  and
post-merger  companies'  revenues  during  2001 and 2000,  compared to the prior
year, are summarized in the following table:

    Sources of Revenue Changes                      2001          2000
    ----------------------------------------------------------------------
    Increase (Decrease)                              (In millions)

    Pre-Merger Companies:

    Electric Utilities (Regulated Services):
      Retail electric sales...................    $(240.5)        $(36.8)
      Other revenues..........................      (22.6)           4.7
    ----------------------------------------------------------------------

    Total Electric Utilities..................     (263.1)         (32.1)
    ----------------------------------------------------------------------

    Unregulated Businesses (Competitive Services):
      Retail electric sales...................      (19.9)         170.7
      Wholesale electric sales................      287.1          105.7
      Gas sales...............................      226.1          376.3
      Other revenues..........................      106.5           88.7
    ----------------------------------------------------------------------

    Total Unregulated Businesses..............      599.8          741.4
    ----------------------------------------------------------------------

    Total Pre-Merger Companies................      336.7          709.3
    ----------------------------------------------------------------------

    Former GPU Companies:
      Electric utilities......................      570.4           --
      Unregulated businesses..................      101.9           --
    ----------------------------------------------------------------------

    Total Former GPU Companies................      672.3           --

    Intercompany Revenues.....................      (38.6)          --
    ----------------------------------------------------------------------

    Net Revenue Increase......................     $970.4         $709.3
    ======================================================================

Electric Sales

          EUOC retail  electric  sales  revenues  for our  pre-merger  companies
decreased by $240.5  million in 2001,  compared to 2000,  primarily due to lower
generation  kilowatt-hour sales reflecting the result of customer choice in Ohio
and the  influence  of a declining  national  economy on our  regional  business
activity, which reduced our distribution deliveries.  Both unit prices and sales
volumes  declined  from the prior year. As a result of opening Ohio to competing
generation  suppliers  in 2001,  sales of  electric  generation  by  alternative
suppliers in our franchise  area  increased to 11.3% of total energy  delivered,
compared to 0.8% in 2000. Consequently, generation kilowatt-hour sales to retail
customers were 12.2% lower in 2001 than the prior year.  Implementation  of a 5%
reduction  in  generation  charges for  residential  customers as part of Ohio's
electric  utility  restructuring  implemented in 2001,  also  contributed  $51.2
million to the  reduced  electric  sales  revenues.  Weather in 2001 had a minor
influence  on sales  with  mild  weather  in the  fourth  quarter  substantially
offsetting a net increase in  weather-related  sales  revenue  through the third
quarter.  Kilowatt-hour  deliveries  to  franchise  customers  were  down a more
moderate  1.7% due in part to the  decline in economic  conditions,  which was a
major  factor  resulting  in a 3.1%  decrease  in  kilowatt-hour  deliveries  to
commercial and industrial customers. Other regulated electric revenues decreased
by $22.6  million in 2001,  compared to the prior  year,  due in part to reduced
customer reservation of transmission capacity.

          Total electric  generation sales increased by 8.3% in 2001 compared to
the prior year with  sales to the  wholesale  market  being the  largest  single
factor  contributing to this increase.  While revenues from the wholesale market
increased  $287.1  million in 2001 from the prior year,  kilowatt-hour  sales to
that market more than doubled as nonaffiliated  energy suppliers made use of the
1,120  megawatts  (MW) supply  commitment  under our Ohio  transition  plan, and
reduced sales to the regulated retail market made additional energy available to
pursue opportunities in the wholesale market.  Retail kilowatt-hour sales by our
competitive  services segment increased by 10.6% in 2001,  compared to 2000. The
increase resulted from expanding  kilowatt-hour sales within Ohio as a result of
retail  customers  switching to FES, our  unregulated  subsidiary,  under Ohio's
electricity  choice  program.  The  higher  kilowatt-hour  sales  in  Ohio  were
partially  offset by lower  sales in markets  outside of Ohio as more  customers
returned to their local distribution companies. Declining sales to higher-priced
eastern markets  contributed to an overall decline in retail  competitive  sales
revenue in 2001 from the prior year,  despite an increase in kilowatt hour sales
in Ohio's competitive market.

<PAGE>


          EUOC retail  revenues  decreased by $36.8  million in 2000 compared to
1999, as a result of lower unit prices, which were partially offset by increased
generation  sales volume.  Despite a milder summer,  retail electric  generation
sales were 2% higher in 2000 than the previous year.  Total electric  generation
sales (including  unregulated  sales) increased 8.4% in 2000,  compared to 1999.
Unregulated  retail sales more than  tripled in 2000  reflecting  our  marketing
efforts to expand retail electric sales to targeted  unregulated  markets in the
eastern seaboard states,  principally the commercial and industrial sectors. The
cooler summer weather reduced retail customer demand,  making more of our energy
available to the wholesale market. As a result, we were able to achieve moderate
growth  in  kilowatt-hour  sales  to that  market  in 2000.  EUOC  kilowatt-hour
deliveries  (to  customers in our  franchise  areas)  increased in 2000 from the
prior year due to  additional  sales to  commercial  and  industrial  customers.
Kilowatt-hour sales to residential  customers  declined.  Other electric utility
revenues  increased in 2000 from the previous  year  primarily due to additional
transmission service revenue.

          Changes in electric  generation sales and  distribution  deliveries in
2001 and 2000 for our  pre-merger  companies  are  summarized  in the  following
table:

    Changes in Kilowatt-hour Sales             2001            2000
    ------------------------------------------------------------------
    Increase (Decrease)
    Electric Generation Sales:
      Retail --
        Regulated services...............    (12.2)%           2.0%
        Competitive services.............     10.6%          229.6%
      Wholesale..........................    165.5%            7.4%
    ------------------------------------------------------------------

    Total Electric Generation Sales......      8.3%            8.4%
    ==================================================================

    EUOC Distribution Deliveries:
      Residential........................      1.7%           (1.2)%
      Commercial and industrial..........     (3.1)%           2.9%
    ------------------------------------------------------------------

    Total Distribution Deliveries........     (1.7)%           1.7%
    ==================================================================

Other Sales

          Natural gas  revenues  were the largest  source of  increases in other
sales in 2001.  Beginning  November  1,  2000,  residential  and small  business
customers  in the  service  area of  Dominion  East Ohio,  a  nonaffiliated  gas
utility,  began shopping among  alternative  gas suppliers as part of a customer
choice  program.  FES took advantage of this  opportunity to expand its customer
base.  The average  number of retail gas  customers  served by FES  increased to
approximately 161,000 in 2001 from approximately 44,000 in 2000. Total gas sales
increased by $226.1 million or 40% from the prior year. In 2000,  retail natural
gas revenues were the largest  source of increase in other sales.  Collectively,
three gas acquisitions in 1999 (Atlas Gas Marketing Inc., Belden Energy Services
Company  and  Volunteer  Energy  LLC),  as well as  increased  retail  marketing
efforts, significantly expanded retail gas revenues. Wholesale gas revenues were
also higher.

Expenses

          Total expenses increased $790.2 million in 2001, which included $542.4
million of  incremental  expenses for the former GPU  companies  during the last
seven weeks of 2001. For our  pre-merger  companies,  total  expenses  increased
$280.4 million in 2001 and $739.8  million in 2000,  compared to the prior year.
Sources of changes in pre-merger and post-merger companies' expenses in 2001 and
2000, compared to the prior year, are summarized in the following table:


      Sources of Expense Changes                    2001          2000
      -------------------------------------------------------------------
      Increase (Decrease)                              (In millions)

      Pre-Merger Companies:

        Fuel and purchased power................   $ 48.7         $125.9
        Purchased gas...........................    266.5          382.9
        Other operating expenses................    178.2          231.7
        Depreciation and amortization...........    (99.0)          (4.3)
        General taxes...........................   (114.0)           3.6
      -------------------------------------------------------------------

      Total Pre-Merger Companies................    280.4          739.8
      -------------------------------------------------------------------

      Former GPU Companies......................    542.4           --

      Intercompany Expenses.....................    (32.6)          --
      -------------------------------------------------------------------

      Net Expense Increase......................   $790.2         $739.8
      ===================================================================

          The  following   comparisons  reflect  variances  for  the  pre-merger
companies only,  excluding the incremental expenses for the former GPU companies
during the last seven weeks of 2001.

          The increase in fuel expense in 2001 compared to 2000 ($24.3  million)
resulted  from the  substitution  of coal and natural gas fired  generation  for
nuclear  generation  (which has lower unit fuel costs than fossil fuel) during a
period of reduced nuclear availability resulting from both planned and unplanned
outages. Coal prices were also higher during that period.  Purchased power costs
increased  early in 2001,  compared  to 2000,  due to higher  winter  prices and
additional  purchased power requirements during that period, with the balance of
the year offsetting all but $24.4 million of that increase, reflecting generally
lower prices and reduced external power needs than last year's.

          In 2000, fuel and purchased  power  increased  $125.9 million due to a
$201.6  million  increase in fuel and  purchased  power  expense of  FirstEnergy
Trading Services Inc. (FETS), a wholly owned subsidiary, reflecting expansion of
its operations to support our retail  marketing  efforts (FETS  operations  were
assumed  by FES in  2001).  Excluding  those  competitive  activities,  fuel and
purchased power costs decreased $75.7 million in 2000,  compared to 1999.  Lower
fuel expense  accounted for all of the reduction,  declining $103.6 million from
1999,  despite a 7%  increase  in the output  from our  generating  units due to
additional nuclear  generation,  the expiration of an above-market coal contract
and continued  improvement in coal blending  strategies.  Purchased  power costs
increased $27.9 million in 2000 from the prior year due to higher average prices
and to additional kilowatt-hours purchased. Purchased gas costs increased 48% in
2001 and 224% in 2000 from the prior year. The increases were due principally to
the expansion of FES's retail gas business.

          Other  operating  expenses  increased by $178.2 million in 2001 and by
$231.7 million in 2000 compared to the prior year. The significant  reduction in
2001 of gains from the sale of  emission  allowances,  higher  fossil  operating
costs and additional  employee benefit costs accounted for $144.5 million of the
increase in 2001.  Additionally,  higher  operating  costs from the  competitive
services business segment due to expanded  operations  contributed $56.9 million
to the increase.  Partially offsetting these higher other operating expenses was
a reduction  in  low-income  payment  plan  customer  costs and a $30.2  million
decrease  in  nuclear  operating  costs in 2001,  compared  to the  prior  year,
resulting from one less refueling outage.

          Fossil  operating costs increased $44.3 million in 2001 from last year
due principally to planned  maintenance work at the Mansfield  generating plant.
Pension costs  increased by $32.6 million in 2001 from the prior year  primarily
due to lower returns on pension plan assets (due to  significant  market-related
reductions in the value of pension plan assets),  the  completion of the 15-year
amortization  of OE's  pension  transition  asset and changes to plan  benefits.
Health care benefit costs also  increased by $21.4 million in 2001,  compared to
2000,  principally  due to an  increase  in the  health  care  cost  trend  rate
assumption for computing post-retirement health care benefit liabilities.

          In 2000, other operating  expenses  increased from 1999 due to several
factors. A significant  portion of the increase resulted from additional nuclear
costs  associated  with three  refueling  outages in 2000  versus two during the
previous year and increased nuclear ownership  resulting from the Duquesne asset
exchange.  Costs incurred to improve the  availability of our fossil  generation
fleet and leased  portable  diesel  generators,  acquired  as part of our summer
supply strategy, added to other expenses for the EUOC in 2000, compared to 1999.
We also incurred increased reserves for potentially  uncollectible accounts from
customers  in the steel  sector as well as a reserve for  expected  construction
contract  losses at FEFSG.  The increase in other  operating  costs in 2000 from
1999 also  reflected an increase in expenses  related to expanded  operations of
the competitive services business segment. Partially offsetting the higher costs
were  increased  gains  of $38.5  million  realized  from  the sale of  emission
allowances in 2000 as well as the absence of  nonrecurring  costs  recognized in
the prior year.

          Charges for depreciation  and amortization  decreased by $99.0 million
in 2001 and $4.3  million  in 2000  from the  prior  year.  Approximately  $64.6
million of the decrease in 2001 resulted from lower incremental  transition cost
amortization  under  FirstEnergy's  Ohio transition plan compared to accelerated
cost  recovery  in  connection  with OE's  prior  rate plan.  The  reduction  in
depreciation and amortization also reflected  additional cost deferrals of $51.2
million for recoverable  shopping  incentives  under the Ohio  transition  plan,
partially offset by increases associated with depreciation on recently completed
combustion turbines.

          In  November  2001,  we  announced  an  agreement  to sell four of our
coal-fired  power plants to NRG Energy,  Inc. The plants meet the criteria under
SFAS 121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to be Disposed Of" and have been  classified  as assets to be disposed of
since November 2001.  Accordingly,  depreciation  of those plants ceased pending
their sale. Due to the cessation of depreciation  on those plants,  depreciation
was  reduced  by $6.6  million in 2001 from what it  otherwise  would have been.
Under  SFAS 121  guidance,  the  long-lived  assets  to be  disposed  of must be
included  on the  balance  sheet at the lower of their  carrying  amount or fair
value less cost to sell (see Outlook - Optimizing the Use of Assets) and at year
end continued to be reported at their carrying amount of $539 million.

<PAGE>

          In 2000,  depreciation and amortization was reduced by $9.8 million in
the  second  half  of the  year,  following  approval  by the  Public  Utilities
Commission of Ohio (PUCO) of  FirstEnergy's  Ohio transition  plan.  Incremental
transition costs recovered in 2001 and cost recovery accelerated under OE's rate
plan and Penn's  restructuring  plan in 2000 and 1999 are  summarized  by income
statement caption in the following table:

  Accelerated Cost Recovery            2001          2000           1999
  ------------------------------------------------------------------------
                                                  (In millions)

  Depreciation and amortization..     $268.0        $332.6          $333.3
  Income tax amortization........       41.1          42.6            18.7
  ------------------------------------------------------------------------

  Total Accelerations............     $309.1        $375.2          $352.0
  ========================================================================

          General taxes declined  $114.0 million from last year primarily due to
reduced  property taxes and other state tax changes in connection  with the Ohio
electric  industry  restructuring.  In  addition,  as a result  of  successfully
resolving certain pending tax issues, a one-time benefit of $15 million was also
recognized in 2001. The reduction in general taxes was partially offset by $66.6
million of new Ohio franchise taxes,  which are classified as state income taxes
on the Consolidated Statements of Income.

Net Interest Charges

          Net interest  charges  increased  $26.6  million in 2001,  compared to
2000. This increase  reflects interest on $4 billion of long-term debt issued by
FirstEnergy in connection  with the merger and related bridge  financing,  which
totaled  $40.4  million.  Excluding the results  associated  with the last seven
weeks of 2001 for the former GPU companies  and  merger-related  financing,  net
interest  charges  decreased $39.8 million in 2001,  compared to a $43.2 million
decrease in 2000 from the prior year.  We continued to redeem and  refinance our
outstanding debt and preferred stock,  maintaining a downward trend in financing
costs during 2001, before the effects of the GPU merger.

          After the merger with GPU became  probable,  we established  cash flow
hedges  under SFAS 133  covering a portion of our future  interest  payments  in
connection  with the anticipated  issuance of $4 billion of  acquisition-related
debt. The hedges provided us with  protection  against a possible upward move in
interest rates but limited our ability to completely participate in the benefits
of a downward  move.  Due to a decline in  interest  rates  during the period in
which cash flow hedges were in place,  FirstEnergy  incurred a net deferred loss
in  connection  with  this   transaction  and  a  related   reduction  in  other
comprehensive  income  totaling $134 million  (after tax).  The cash flow hedges
were the primary  contributor to the current net deferred loss of $169.4 million
included in Accumulated Other  Comprehensive Loss (AOCL) as of December 31, 2001
for derivative  hedging  activity.  In accordance with the  requirements of SFAS
133,  this  amount is being  amortized  from AOCL to interest  expense  over the
corresponding interest payment periods hedged - 5, 10 and 30 years.

Results of Operations - Business Segments

          We manage our  business  as two  separate  major  business  segments -
regulated  services and competitive  services.  The regulated  services  segment
designs, constructs,  operates and maintains our regulated domestic transmission
and  distribution  systems.  It also provides  generation  services to franchise
customers who have not chosen an alternative generation supplier. OE, CEI and TE
(Ohio  Companies) and Penn obtain  generation  through a power supply  agreement
with the competitive services segment (see Outlook - Business Organization). The
competitive  services segment includes all unregulated energy and energy-related
services  including  commodity  sales (both  electricity and natural gas) in the
retail and wholesale  markets,  marketing,  generation,  trading and sourcing of
commodity  requirements,   as  well  as  other  competitive  energy  application
services. Competitive products are increasingly marketed to customers as bundled
services,  often under  master  contracts.  Financial  results  discussed  below
include  intersegment  revenue. A reconciliation of segment financial results to
consolidated  financial  results  is  provided  in  Note 7 to  the  consolidated
financial statements.

Regulated Services

          Net income  increased  to $640.2  million in 2001,  compared to $464.4
million in 2000 and $413.9  million in 1999.  Excluding  the last seven weeks of
2001 results  associated with the former GPU companies,  net income increased by
$98.7 million in 2001.  The increases in pre-merger net income are summarized in
the following table:

<PAGE>


    Regulated Services                               2001          2000
    ----------------------------------------------------------------------
    Increase (Decrease)                                 (In millions)

    Revenues....................................   $(130.2)      $ 57.5

    Expenses....................................    (345.2)        54.1
    ---------------------------------------------------------------------

    Income Before Interest and Income Taxes.....     215.0          3.4
    ---------------------------------------------------------------------

    Net interest charges........................     (16.8)       (55.9)
    Income taxes................................     133.1          8.8
    ---------------------------------------------------------------------

    Net Income Increase.........................   $  98.7       $ 50.5
    =====================================================================

          Distribution throughput was 1.7% lower in 2001, compared to 2000,
reducing external revenues by $245.7 million. Partially offsetting the decrease
in external revenues were revenues from FES for the rental of fossil generating
facilities and the sale of generation from nuclear plants, resulting in a net
$130.2 million reduction to total revenues. Expenses were $345.2 million lower
in 2001 than 2000 due to lower purchased power, depreciation and amortization
and general taxes, offset in part by higher other operating expenses. Lower
generation sales reduced the need to purchase power from FES, with a resulting
$269.0 million decline in those costs in 2001 from the prior year. Other
operating expenses increased by $178.5 million in 2001 from the previous year
reflecting a significant reduction in 2001 of gains from the sale of emission
allowances, higher fossil operating costs and additional employee benefit costs.
Lower incremental transition cost amortization and the new shopping incentive
deferrals under FirstEnergy's Ohio transition in 2001 plan as compared with the
accelerated cost recovery in connection with OE's prior rate plan in 2000
resulted in a $131.0 million reduction in depreciation and amortization in 2001.
A $123.6 million decrease in general taxes in 2001 from the prior year primarily
resulted from reduced property taxes and other state tax changes in connection
with the Ohio electric industry restructuring.

          Lower unit prices in 2000  compared to 1999  produced a $33.2  million
decrease in revenues from nonaffiliates despite a 1.7% increase in kilowatt-hour
deliveries.  Rental of fossil  generating  facilities and the sale of generation
from nuclear plants more than offset the reduced external revenue resulting in a
net $57.5 million increase in total revenues.  Expenses  increased $54.1 million
in 2000 from 1999 primarily due to higher  purchased  power costs resulting from
higher average prices and additional megawatt-hours purchased, as well as higher
other operating costs. Interest charges in 2000 decreased $55.9 million compared
to 1999,  reflecting the impact of net debt redemptions and refinancings and was
the primary contributor to the increase in net income.

Competitive Services

          Net income  decreased  to $57.2  million in 2001,  compared  to $137.2
million in 2000 and $129.2  million in 1999.  Excluding  the last seven weeks of
2001 results  associated  with the former GPU  companies,  net income  decreased
$83.0 million in 2001.  The changes to pre-merger  net income are  summarized in
the following table:

      Competitive Services                             2001           2000
      ----------------------------------------------------------------------
      Increase (Decrease)                                 (In millions)

      Revenue.....................................    $254.1         $789.6

      Expenses....................................     366.9          773.5
      ----------------------------------------------------------------------

      Income Before Interest and Income Taxes.....    (112.8)          16.1
      ----------------------------------------------------------------------

      Net interest charges........................      13.5            2.6
      Income taxes................................     (51.8)           5.5
      Cumulative effect of a change in accounting.      (8.5)          --
      ---------------------------------------------------------------------

      Net Income Increase (Decrease)..............    $(83.0)        $  8.0
      ======================================================================

          Sales to nonaffiliates  increased $523.1 million in 2001,  compared to
the prior year, with electric revenues contributing $260.1 million,  natural gas
revenues  $226.1  million and the balance of the  increase  from  energy-related
services.  Reduced power  requirements by the regulated services segment reduced
internal revenues by $269.0 million.  Expenses  increased $366.9 million in 2001
from 2000 primarily due to a $266.5 million  increase in purchased gas costs and
increases  resulting from additional fuel and purchased power costs (see Results
of Operations) as well as higher expenses for energy-related  services.  Reduced
margins for both major competitive product areas - electricity and natural gas -
contributed to the reduction in net income,  along with higher interest  charges
and the  cumulative  effect  of the  SFAS 133  accounting  change.  Margins  for
electricity and gas sales were both adversely affected by higher fuel costs.

           In 2000, sales to nonaffiliates increased $749.3 million, compared to
the prior year, with electric revenues contributing $283.5 million, natural gas
revenues $376.3 million and the balance of the increase from energy-related
services. Additional power sales to the regulated services segment increased
revenues by $40.3 million. Expenses


<PAGE>


increased  $773.6  million  in 2000 from 1999  primarily  due to the  additional
purchased gas and purchased power costs resulting from the increased  sales. The
exchange of fossil  assets for nuclear  assets with  Duquesne  Light  Company in
December 1999 changed the mix of expenses,  increasing plant operating costs and
decreasing fuel expense.  The resulting net income increase primarily  reflected
the contribution of competitive electric sales offset in part by higher interest
charges.

Capital Resources and Liquidity

          We had approximately $220.2 million of cash and temporary  investments
and $614.3 million of short-term  indebtedness  on December 31, 2001. Our unused
borrowing capability included $1.115 billion under revolving lines of credit and
$84 million  from unused bank  facilities.  At the end of 2001,  OE, CEI, TE and
Penn had the capability to issue $2.2 billion of additional first mortgage bonds
(FMB) on the basis of property  additions and retired bonds. The former GPU EUOC
will not issue FMB other than as collateral for senior notes, since their senior
note  indentures  prohibit  (subject  to certain  exceptions)  the GPU EUOC from
issuance of any debt which is senior to the senior  notes.  As of  December  31,
2001, the GPU EUOC had the capability to issue $795 million of additional senior
notes  based  upon FMB  collateral.  At year end  2001,  based  upon  applicable
earnings  coverage tests and their respective  charters,  OE, Penn, TE and JCP&L
could issue $7.0 billion of preferred  stock  (assuming no  additional  debt was
issued).  CEI,  Met-Ed and  Penelec  have no  restrictions  on the  issuance  of
preferred stock.

          At the end of 2001, our common equity as a percentage of
capitalization, including debt relating to assets held for sale, stood at 35%
compared to 42% at the end of 2000. This decrease resulted from the addition of
$8.2 billion of debt, $378 million of preferred stock and $2.6 billion of common
stock (issued to former GPU stockholders) to our capital structure as a result
of the GPU acquisition. The incremental debt included $6.0 billion of the former
GPU companies' debt, $1.5 billion of which was replaced with FirstEnergy debt
and an additional $2.2 billion of FirstEnergy debt used to pay GPU shareholders
as part of the merger.

          Following  approval of our merger with GPU by the New Jersey  Board of
Public  Utilities  (NJBPU)  on  September  26,  2001 and by the  Securities  and
Exchange  Commission  on October 29,  2001,  Standard & Poor's (S&P) and Moody's
Investors Service established  initial credit ratings for FirstEnergy's  holding
company and adjusted  those of our EUOC to reflect our new  consolidated  credit
profile.  S&P's  outlook on all our credit  ratings is stable.  On February  22,
2002,  Moody's  announced  a change in its  outlook  for the  credit  ratings of
FirstEnergy,  Met-Ed and Penelec from stable to  negative.  The change was based
upon a  decision  by the  Commonwealth  Court of  Pennsylvania  to remand to the
Pennsylvania  Public Utility Commission (PPUC) for  reconsideration its decision
regarding rate relief, accounting deferrals and the mechanism for sharing merger
savings  rendered in  connection  with its approval of the GPU merger (see State
Regulatory Matters-Pennsylvania).

          Our cash  requirements  in 2002 for operating  expenses,  construction
expenditures,  scheduled debt  maturities and preferred  stock  redemptions  are
expected  to be  met  without  increasing  our  net  debt  and  preferred  stock
outstanding.   Major  contractual  obligations  for  future  cash  payments  are
summarized in the following table:

<TABLE>
<CAPTION>

Contractual Obligations               2002       2003      2004        2005       2006    Thereafter    Total
-------------------------------------------------------------------------------------------------------------
                                                                  (In millions)

<S>                                 <C>        <C>        <C>        <C>        <C>        <C>         <C>
Long-term debt*................     $1,205     $  711     $1,179     $  854     $1,433     $ 7,596     $12,978
Short-term borrowings*.........        614         --         --         --         --          --         614
Mandatory preferred stock......         30         13         13          4          4         572         636
Capital leases ................          6          6          6          5          6          10          39
Operating leases ..............        153        156        184        186        183       2,036       2,898
Unconditional fuel and power
   purchases...................      2,493      1,584      1,369      1,219      1,250       6,056      13,971
--------------------------------------------------------------------------------------------------------------
         Total*                     $4,501     $2,470     $2,751     $2,268     $2,876     $16,270     $31,136
==============================================================================================================

<FN>

*  Excludes approximately $1.75 billion of long-term debt and $233.8 million of
   short-term borrowings related to pending divestitures discussed below.
</FN>
</TABLE>


          Our capital  spending for the period 2002-2006 is expected to be about
$3.4 billion  (excluding  nuclear  fuel),  of which  approximately  $850 million
applies to 2002.  Investments  for additional  nuclear fuel during the 2002-2006
period are  estimated  to be  approximately  $536  million,  of which  about $54
million applies to 2002.  During the same period,  our nuclear fuel  investments
are  expected to be reduced by  approximately  $507  million  and $101  million,
respectively, as the nuclear fuel is consumed.

          Off balance sheet obligations  primarily consist of sale and leaseback
arrangements  involving  Perry  Unit  1,  Beaver  Valley  Unit 2 and  the  Bruce
Mansfield Plant,  which are reflected in the operating lease payments  disclosed
above (see Note 3). The present value as of December 31, 2001, of these sale and
leaseback operating lease commitments,


<PAGE>


net of trust investments,  total $1.5 billion. CEI and TE sell substantially all
of their retail customer receivables, which provided $200 million of off balance
sheet financing as of December 31, 2001 (see Note 1 - Revenues).

          FirstEnergy's  sale of the former GPU subsidiary,  GasNet, in December
2001, eliminated $290 million of debt and also provided $125 million of net cash
proceeds,  which were used to reduce  short-term  borrowings.  Expected proceeds
from the pending sales of four fossil plants and Avon Energy Partners  Holdings,
a wholly owned subsidiary, are shown in the following table:

 Completed and Pending Divestitures
                         Cash             Debt
                       Proceeds         Removed           Transaction Date**
--------------------------------------------------------------------------------
 Completed Sale
 --------------
    GasNet           $125 million     $290 million        December 2001

 Pending Sales:
 --------------
   Avon Energy       $238 million*    $1.7 billion        Second Quarter 2002
   Lake Plants       $1.355 billion   $145 million        Mid-2002
 -------------------------------------------------------------------------------

 *   Based on receipt of $150 million at closing and the present value of $19
     million per year to be received over six years beginning in 2003.
 **  Estimated closing dates for pending sales.

FirstEnergy continues to pursue divestiture of the remainder of its
international operations (see Outlook - Optimizing the Use of Assets).

Market Risk Information

          We use various market risk sensitive instruments, including derivative
contracts,  primarily  to manage the risk of price,  interest  rate and  foreign
currency  fluctuations.  Our  Risk  Policy  Committee,  comprised  of  executive
officers,  exercises an independent risk oversight function to ensure compliance
with corporate risk management policies and prudent risk management practices.

Commodity Price Risk

          We are  exposed  to  market  risk  primarily  due to  fluctuations  in
electricity,  natural gas and coal prices. To manage the volatility  relating to
these exposures,  we use a variety of non-derivative and derivative instruments,
including  forward  contracts,   options,   futures  contracts  and  swaps.  The
derivatives  are used  principally  for hedging  purposes  and, to a much lesser
extent,  for  trading  purposes.  The  change  in the fair  value  of  commodity
derivative  contracts  related to energy production during 2001 is summarized in
the following table:

  Increase (Decrease)in the Fair Value of Commodity Derivative Contracts
  ------------------------------------------------------------------------
                                                             (In millions)
  Outstanding as of January 1, 2001 with
    SFAS 133 cumulative adjustment.........................     $ 60.5
  Acquisition of GPU.......................................       14.9
  Contract value when entered..............................        0.6
  Increase/(decrease) in value of existing contracts.......      (97.1)
  Change in techniques/assumptions.........................       --
  Settled contracts........................................      (45.3)
  ----------------------------------------------------------------------
  Outstanding as of December 31, 2001......................     $(66.4)*
  ======================================================================

  * Does not include $11.6 million of derivative contract fair
    value increase, as of December 31, 2001, representing our
    50% share of Great Lakes Energy Partners, LLC


          While the valuation of derivative  contracts is always based on active
market prices when they are available, longer-term contracts can require the use
of  model-based  estimates  of  prices  in later  years  due to the  absence  of
published market prices.  We currently use modeled prices for the later years of
some electric contracts.  Our model incorporates  explicit assumptions regarding
future supply and demand and fuel prices.  The model  provides  estimates of the
future prices for electricity and an estimate of price  volatility.  We make use
of these  results in  developing  estimates of fair value for the later years of
those  electric  contracts  for  financial  reporting  purposes  as  well as for
internal management decision making. Sources of information for the valuation of
derivative contracts by year are summarized in the following table:

<PAGE>


Source of Information - Fair Value by Contract Year
                            2002      2003       2004    Thereafter    Total
-----------------------------------------------------------------------------
                                             (In millions)
Prices actively quoted...  $(54.1)   $(19.9)   $ (3.2)    $ --       $(77.2)
Prices based on models...    --        --        (8.1)      18.9       10.8
                           --------------------------------------------------

   Total.................  $(54.1)   $(19.9)   $(11.3)     $18.9     $(66.4)
=============================================================================


          We perform sensitivity analyses to estimate our exposure to the market
risk of our  commodity  position.  A  hypothetical  10% adverse  shift in quoted
market  prices in the near term on both our  trading and  nontrading  derivative
instruments  would not have had a material effect on our consolidated  financial
position  or cash flows as of December  31,  2001.  We  estimate  that if energy
commodity  prices move on average 10 percent higher or lower,  pretax income for
the  next  twelve   months  would   increase  or  decrease,   respectively,   by
approximately $2.4 million.

Interest Rate Risk

          Our exposure to fluctuations in market interest rates is reduced since
a  significant  portion of our debt has fixed  interest  rates,  as noted in the
table on the following page. We are subject to the inherent  interest rate risks
related  to  refinancing  maturing  debt by  issuing  new  debt  securities.  As
discussed in Note 3 to the consolidated financial statements, our investments in
capital  trusts  effectively  reduce  future lease  obligations,  also  reducing
interest rate risk.  Changes in the market value of our nuclear  decommissioning
trust   funds  are   recognized   by  making   corresponding   changes   to  the
decommissioning  liability, as described in Note 1 to the consolidated financial
statements.

<TABLE>
<CAPTION>


Comparison of Carrying Value to Fair Value
------------------------------------------------------------------------------------------------------------------
                                                                                       There-                Fair
                                2002        2003      2004       2005       2006       after      Total     Value
------------------------------------------------------------------------------------------------------------------
                                                                (Dollars in millions)
<S>                            <C>         <C>        <C>       <C>        <C>         <C>       <C>       <C>
Investments other than Cash
   and Cash Equivalents:

Fixed Income.................  $  101      $  97      $314      $  58      $   75      $1,901    $ 2,546   $ 2,568
   Average interest rate.....     6.7%       7.7%      7.8%       7.9%        7.9%        6.6%       6.9%
-------------------------------------------------------------------------------------------------------------------
___________________________________________________________________________________________________________________

Liabilities
-------------------------------------------------------------------------------------------------------------------
Long-term Debt:*
Fixed rate...................  $1,089      $ 706      $923      $ 851      $1,411      $6,519    $11,499   $11,698
   Average interest rate ....     8.2%       7.6%      7.2%       8.1%        5.8%        7.1%       7.2%
Variable rate..............  ..$   35      $   5      $256      $   3      $   22      $1,077    $ 1,398   $ 1,399
   Average interest rate.....     5.2%      11.5%      3.1%      10.2%        5.2%        3.0%       3.1%
Short-term Borrowings*...... . $  614                                                            $   614   $   614
   Average interest rate.....     2.8%                                                               2.8%
-------------------------------------------------------------------------------------------------------------------
Preferred Stock.............  .$   30      $  13      $ 13      $   4      $    4      $  572    $   636   $   626
   Average dividend rate ....     8.7%       8.3%      8.3%       7.5%        7.5%        8.3%       8.3%
-------------------------------------------------------------------------------------------------------------------

<FN>

* Excludes approximately $1.75 billion of long-term debt and $233.8 million of
short-term borrowings related to pending divestitures.

</FN>
</TABLE>


Interest Rate Swap Agreements

          Penelec, GPU Power through a subsidiary and GPU Electric, Inc.
(through GPU Power UK) use interest rate swap agreements, denominated in dollars
and sterling, to manage the risk of increases in variable interest rates. All of
the agreements convert variable rate debt to fixed rate debt. As of December 31,
2001, interest rate swaps denominated in dollars had a weighted average fixed
interest rate of 6.99%; those in sterling had a weighted average fixed interest
rate of 6.00%. The following summarizes the principal characteristics of the
swap agreements in effect as of December 31, 2001:


         Interest Rate Swaps as of December 31, 2001
         ------------------------------------------------------------------
                                   Notional        Maturity        Fair
         Denomination              Amount           Date          Value
         ------------              ------           ----          -----
         (Dollars/Sterling in millions)
         Dollars                      50            2002           (1.8)
         Dollars                      26            2005           (1.1)
         Sterling                    125            2003           (2.3)
         ------------------------------------------------------------------



<PAGE>


Foreign Currency Swap Agreements

          GPU Electric  uses currency  swap  agreements to manage  currency risk
caused by fluctuations in the US dollar exchange rate related to bonds issued in
the US by Avon Energy,  which owns GPU Power UK. These swap  agreements  convert
principal  and  interest  payments  on this US  dollar  debt to  fixed  sterling
principal and interest payments,  and expire on the maturity dates of the bonds.
Interest  expense  is  recorded  based  on the  fixed  sterling  interest  rate.
Characteristics of currency swap agreements  outstanding as of December 31, 2001
are summarized in the following table:

   Currency Swaps - Dollars/Sterling
   -----------------------------------------------------------------------

                                                   Weighted
      Notional Amount         Maturity     Average Interest Rate    Fair
   ---------------------                   ---------------------
      USD       Sterling       Date          USD      Sterling     Value
   ---------    --------       ----          ---      --------     -----
   (Dollars/Sterling in millions)
      350         212          2002          6.73%      7.66%      $46.3
      250         152          2007          7.05%      7.72%      $26.3
      250         153          2008          6.46%      6.94%      $23.7
  -----------------------------------------------------------------------


Outlook

          We continue to pursue our goal of being the leading regional  supplier
of energy  and  related  services  in the  northeastern  quadrant  of the United
States,  where we see the best  opportunities  for growth.  We intend to provide
competitively  priced,  high-quality  products and value-added services - energy
sales and services,  energy  delivery,  power supply and  supplemental  services
related to our core  business.  As our  industry  changes to a more  competitive
environment,  we have  taken and  expect to take  actions  designed  to create a
larger,  stronger regional  enterprise that will be positioned to compete in the
changing energy marketplace.

Business Organization

          Beginning in 2001,  Ohio utilities that offered both  competitive  and
regulated  retail  electric  services  were  required  to  implement a corporate
separation  plan  approved by the PUCO - one which  provided a clear  separation
between  regulated and  competitive  operations.  Our business is separated into
three  distinct units - a competitive  services unit, a regulated  services unit
and a corporate  support unit. FES provides  competitive  retail energy services
while the EUOC  continue  to provide  regulated  transmission  and  distribution
services. FirstEnergy Generation Corp. (FGCO), a wholly owned subsidiary of FES,
leases fossil and hydroelectric  plants from the EUOC and operates those plants.
We expect the transfer of ownership  of EUOC  generating  assets to FGCO will be
substantially completed by the end of the market development period in 2005. All
of the  EUOC  power  supply  requirements  for the Ohio  Companies  and Penn are
provided by FES to satisfy their "provider of last resort" (PLR) obligations, as
well as grandfathered wholesale contracts.

Optimizing the Use of Assets

          A significant step toward being the leading regional supplier in our
target market was achieved when we merged with GPU in November, making us the
fourth largest investor-owned electric system in the nation based on the number
of customers served. Through the merger we can create a stronger enterprise with
greater resources and more opportunities to provide value to our customers,
shareholders and employees. However, additional steps must be taken in order to
deliver the full value of the merger. While GPU's former domestic electric
utility companies fit well with our regional market focus, GPU's former
international companies do not. In December 2001, we divested GasNet, an
Australian gas transmission company. Also, the sale of most of our interest in
Avon Energy - the holding company for Midlands Electricity plc - to Aquila, Inc.
(formerly UtiliCorp United) is pending. The transaction must be completed by
April 26, 2002, or either party may terminate the original agreement. On March
18, 2002, we announced that we finalized terms of the agreement under which
Aquila will acquire a 79.9 percent interest in Avon for approximately $1.9
billion (including the transfer of $1.7 billion of debt). We and Aquila together
will own all of the outstanding shares of Avon through a jointly owned
subsidiary, with each company having a 50-percent voting interest. GPU's other
foreign companies (excluding GPU Power) are held for sale including our
investment in Empresa Distribuidora Electrica Regional S.A. The pending
divestitures should increase our financial flexibility by reducing debt and
preferred stock, and aid us in providing more competitively priced products and
services.

          On November  29,  2001,  we announced an agreement to sell four of our
older  coal-fired  power plants  located  along Lake Erie in Ohio to NRG Energy,
Inc. Under the  agreement,  the  Ashtabula,  Bay Shore,  Eastlake and Lake Shore
generating plants with a total net generating capacity of 2,535 MW will be sold.
The transaction  includes our purchase of up to 10.5 billion  kilowatt-hours  of
electricity  annually,  similar  to the  average  annual  output of the  plants,
through 2005 (the end of the market  development  period  under Ohio's  Electric
Choice Law). The transaction is subject to the receipt of

<PAGE>




necessary regulatory approvals. This transaction is consistent with our strategy
of aggressively pursuing cost savings to maintain  competitively priced products
and  services.  The sale will  allow us to more  closely  match  our  generating
capabilities to the load profiles of our customers,  resulting in more efficient
operation of our remaining  generating  units. It also enables us to concentrate
on our coal-fired  generation along the Ohio River,  which should  contribute to
added supply  efficiencies.  The net, after-tax gain from the sale, based on the
difference  between the sale price of the plants and their  market price used in
our Ohio  restructuring  transition  plan,  will be  credited  to  customers  by
reducing the transition cost recovery period.  We expect to use the net proceeds
from the sale for the  redemption  of high cost debt and  preferred  stock or to
reduce other outstanding obligations to provide additional cost savings.

State Regulatory Matters

          As of January 1, 2001, customers in all of our service areas, covering
portions of Ohio,  Pennsylvania and New Jersey,  could select alternative energy
suppliers.  Our EUOC continue to deliver power to homes and  businesses  through
their existing distribution systems, which remain regulated. Customer rates have
been restructured  into separate  components to support customer choice. In each
of the states,  we have a continuing  responsibility  to provide  power to those
customers not choosing to receive  power from an  alternative  energy  supplier,
subject to certain limits. However, despite similarities,  the specific approach
taken by each state and for each of our regulated companies varies.

          Regulatory assets are costs which the respective  regulatory  agencies
have authorized for recovery from customers in future periods and,  without such
authorization,  would have been charged to income when incurred. The increase in
those assets in 2001 is primarily  the result of the  acquisition  of the former
GPU  companies.  All of the  regulatory  assets are  expected  to continue to be
recovered under the provisions of the respective transition and regulatory plans
as discussed  below.  The regulatory  assets of the individual  companies are as
follows:



<PAGE>


       Regulatory Assets as of December 31,
-----------------------------------------------------
Company                       2001             2000
-------                       ----             ----
                                   (In millions)
OE.......................    $2,025.4        $2,238.6
CEI......................       874.5           816.2
TE.......................       388.8           412.7
Penn.....................       208.8           260.2
Met-Ed...................     1,320.5            --
Penelec..................       769.8            --
JCP&L....................     3,324.8            --
                             --------        --------
   Total.................    $8,912.6        $3,727.7
                             ========        ========



Ohio -

          Beginning on January 1, 2001, Ohio customers were able to choose their
electricity  suppliers.  Customer rates of OE, CEI and TE were  restructured  to
establish  separate charges for transmission and  distribution,  transition cost
recovery  and a  generation-related  component.  When one of our Ohio  customers
elects to obtain  power from an  alternative  supplier,  the  regulated  utility
company reduces the customer's bill with a "generation  shopping  credit," based
on the  regulated  generation  component  plus an  incentive,  and the  customer
receives a generation charge from the alternative  supplier.  Our Ohio EUOC have
continuing  responsibility  to provide energy to  service-area  customers as PLR
through December 31, 2005.

          The transition  cost portion of rates provides for recovery of certain
amounts not otherwise  recoverable in a competitive  generation  market (such as
regulatory  assets).  Transition costs are paid by all customers  whether or not
they choose an alternative supplier. Under the PUCO-approved transition plan, we
assumed the risk of not  recovering up to $500 million of transition  revenue if
the rate of customers (excluding contracts and full-service  accounts) switching
their  service  from  OE,  CEI and TE does  not  reach  20% for any  consecutive
twelve-month  period by December  31,  2005 - the end of the market  development
period. As of December 31, 2001, the  customer switching  rate, on an annualized
basis,  implies  that our risk of not  recovering  transition  revenue  has been
reduced  to  approximately  $174  million.  We  are  also  committed  under  the
transition  agreement to make available  1,120 MW of our generating  capacity to
marketers,  brokers, and aggregators at set prices, to be used for sales only to
retail  customers  in  our  Ohio  service  areas.  Through  December  31,  2001,
approximately  1,032 MW of the 1,120 MW supply  commitment  had been  secured by
alternative suppliers. We began accepting customer applications for switching to
alternative suppliers on December 8, 2000; as of December 31, 2001 our Ohio EUOC
had been  notified  that over 600,000 of their  customers  requested  generation
services  from  other  authorized  suppliers,  including  FES,  a  wholly  owned
subsidiary.


<PAGE>


Pennsylvania -

          Choice of energy  suppliers by  Pennsylvania  customers  was phased in
starting in 1999 and was completed by January 1, 2001. The  Pennsylvania  Public
Utility Commission (PPUC) authorized rate  restructuring  plans for Penn, Met-Ed
and  Penelec,  establishing  separate  charges for  transmission,  distribution,
generation and stranded cost recovery, which is recovered through a "competitive
transition charge" (CTC).  Pennsylvania  customers electing to obtain power from
an  alternative  supplier  have  their  bills  reduced  based  on the  regulated
generation  component,  and the customers  receive a generation  charge from the
alternative supplier.

          In  June  2001,  Met-Ed,   Penelec  and  FirstEnergy  entered  into  a
settlement  agreement  with  major  parties  in the  combined  merger  and  rate
proceedings  that, in addition to resolving certain issues concerning the PPUC's
approval of the GPU merger,  also addressed  Met-Ed's and Penelec's  request for
PLR rate relief. Met-Ed and Penelec are permitted to defer, for future recovery,
the  difference  between their actual energy costs and those  reflected in their
capped  generation  rates.  Those costs will  continue  to be  deferred  through
December 31, 2005.  If energy costs  incurred by Met-Ed and Penelec  during that
period are below their respective  capped generation rates, the difference would
be used to reduce their recoverable  deferred costs.  Met-Ed's and Penelec's PLR
obligations were extended through December 31, 2010.  Met-Ed's and Penelec's CTC
revenues will be applied first to PLR costs,  then to stranded  costs other than
for  non-utility  generation  (NUG) and finally to NUG  stranded  costs  through
December  31,  2010.  Met-Ed and  Penelec  would be  permitted  to  recover  any
remaining  stranded costs through a continuation  of the CTC, after December 31,
2010,  however,  such recovery  would extend to no later than December 31, 2015.
Any amounts not  expected to be  recovered by December 31, 2015 would be written
off at the time such nonrecovery becomes probable.  Several parties had appealed
this PPUC decision to the Commonwealth  Court of  Pennsylvania.  On February 21,
2002, the Court affirmed the PPUC decision regarding approval of the GPU merger,
remanding  the  decision  to the PPUC only with  respect  to the issue of merger
savings. The Court reversed the PPUC's decision regarding the PLR obligations of
Met-Ed and  Penelec,  and denied the related  requests for rate relief by Met-Ed
and Penelec.  We are  considering  our response to the Court's  decision,  which
could include asking the Pennsylvania  Supreme Court to review the decision.  We
are unable to predict the outcome of these matters.

New Jersey -

          Customers  of JCP&L  were  able to  choose  among  alternative  energy
suppliers  beginning  in late  1999.  To  support  customer  choice,  rates were
restructured  into  unbundled  service  charges  and  additional  non-bypassable
charges to recover stranded costs (confirmed by a NJBPU Final Decision and Order
issued  in  March  2001).  JCP&L  has a PLR  obligation,  referred  to as  Basic
Generation  Service  (BGS),  until July 31, 2002.  For the period from August 1,
2002 to July 31, 2003,  the NJBPU has  authorized  the auctioning of BGS to meet
the electric demands of customers who have not selected an alternative supplier.
The auction was successfully concluded on February 13, 2002, thereby eliminating
JCP&L's  obligation  to provide for the energy  requirements  of BGS during that
period.  Beginning  August 1, 2003,  the approach to be taken in  procuring  the
energy needs for BGS has not been  determined.  The NJBPU  recently  initiated a
formal proceeding to decide how BGS will be handled after the transition period.
JCP&L is  permitted  to defer, for  future  recovery, the  amount  by which  its
reasonable  and  prudently  incurred  costs for  providing  BGS to  non-shopping
customers and costs  incurred  under NUG  agreements  exceed  amounts  currently
reflected in its BGS rate and market transition charge rate (for the recovery of
stranded costs).

          On September 26, 2001,  the NJBPU  approved the GPU merger  subject to
the  terms  and  conditions  set  forth in a  settlement  agreement  with  major
intervenors.  As part of the  settlement,  we  agreed to  reduce  JCP&L's  costs
deferred for future recovery by $300 million,  in order to ensure that customers
receive the benefit of future  merger  savings.  JCP&L wrote off $300 million of
its deferred costs in October 2001 upon receipt of the final regulatory approval
for the merger, which occurred on October 29, 2001.

          On February 6, 2002,  JCP&L received a Financing  Order from the NJBPU
with  authorization  to issue $320 million of transition bonds to securitize the
recovery of bondable  stranded costs  associated  with the  previously  divested
Oyster Creek  nuclear  generating  station.  The Order grants JCP&L the right to
charge a usage-based,  non-bypassable  transition  bond charge (TBC) and provide
for the  transfer of the  bondable  transition  property  relating to the TBC to
JCP&L  Transition  Funding LLC  (Transition  Funding),  a wholly  owned  limited
liability  corporation.  Transition  Funding is expected to issue and sell up to
$320 million of transition  bonds that will be  recognized  on our  Consolidated
Balance Sheet in the second quarter of 2002, with the TBC providing  recovery of
principal, interest and related fees on the transition bonds.

FERC Regulatory Matters

          On December 19, 2001, the Federal Energy Regulatory  Commission (FERC)
issued  an order in which it  stated  that the  Alliance  Regional  Transmission
Organization  (Alliance TransCo) did not meet agency requirements to operate the
Alliance TransCo as an approved  Regional  Transmission  Organization  (RTO). It
further concluded that National Grid could be the independent Managing Member of
the Alliance  TransCo.  FERC ordered the Alliance  TransCo and National  Grid to
refile their business plan to consider operating as an independent  transmission
company within the

<PAGE>


Midwest ISO or another RTO. The order gave the Alliance  TransCo 60 days to file
a status report.  On January 22, 2002, the Alliance  TransCo  companies  filed a
series of rehearing applications with FERC.

Supply Plan

          As  part  of  the  Restructuring   Orders  for  the  States  of  Ohio,
Pennsylvania,  and New Jersey, the FirstEnergy companies are obligated to supply
electricity  to  customers  who do not choose an alternate  supplier.  The total
forecasted  peak of this  obligation  in 2002 is 20,300 MW  (10,100  MW in Ohio,
5,400 MW in New  Jersey,  and  4,800 MW in  Pennsylvania).  The  successful  BGS
auction in New Jersey removed JCP&L's BGS obligation for 5,100 MW for the period
from  August 1, 2002 to July 31,  2003.  In that  auction  FES was a  successful
bidder  to  provide  1,700 MW  during  the same  period  to JCP&L  and two other
electric  utilities in New Jersey.  Our current supply portfolio contains 13,283
MW of owned generation and  approximately  1,600 MW of long-term  purchases from
non-utility generators. The remaining obligation is expected to be met through a
mix of multi-year  forward  purchases,  short-term  forward (less than one year)
purchases and spot market purchases.

          The announced sale of four fossil  generating plants expected to close
in mid-2002,  will have little  impact on our supply plan.  As part of the asset
sale,  FirstEnergy has a power purchase agreement under which the purchaser will
provide a similar amount of electricity  as was expected  before the sale.  This
power purchase  agreement runs from the close of the sale  transaction,  through
December 31,  2005,  which is the end of the market  development  period for the
Ohio operating companies.

          Unregulated retail sales are generally  short-term  arrangements (less
than 18 months) at prevailing  market prices.  They are primarily hedged through
short-term  purchased  power  contracts,  supplemented  by  any  of  our  excess
generation when available and economical.

Environmental Matters

          We are in  compliance  with  the  current  sulfur  dioxide  (SO2)  and
nitrogen oxide (NOx) reduction  requirements  under the Clean Air Act Amendments
of  1990.  In  1998,  the   Environmental   Protection  Agency  (EPA)  finalized
regulations  requiring additional NOx reductions in the future from our Ohio and
Pennsylvania  facilities.  Various  regulatory  and judicial  actions have since
sought to further define NOx reduction  requirements (see Note 6 - Environmental
Matters).  We continue to evaluate  our  compliance  plans and other  compliance
options.

          Violations  of  federally  approved  SO2  regulations  can  result  in
shutdown of the generating unit involved  and/or civil or criminal  penalties of
up to  $27,500  for  each  day a unit is in  violation.  The EPA has an  interim
enforcement  policy for SO2 regulations in Ohio that allows for compliance based
on a 30-day averaging  period. We cannot predict what action the EPA may take in
the future with respect to the interim enforcement policy.

          In 1999 and 2000,  the EPA  issued  Notices  of  Violation  (NOV) or a
Compliance Order to nine utilities covering 44 power plants,  including the W.H.
Sammis  Plant.  In addition,  the U.S.  Department  of Justice filed eight civil
complaints against various investor-owned utilities,  which included a complaint
against OE and Penn.  The NOV and complaint  allege  violations of the Clean Air
Act (CAA).  The civil  complaint  against OE and Penn requests  installation  of
"best available control  technology" as well as civil penalties of up to $27,500
per day. Although unable to predict the outcome of these proceedings, we believe
the  Sammis  Plant  is in full  compliance  with  the CAA and  that  the NOV and
complaint  are without  merit.  Penalties  could be imposed if the Sammis  Plant
continues  to operate  without  correcting  the alleged  violations  and a court
determines that the allegations are valid. The Sammis Plant continues to operate
while these proceedings are pending.

          In  December  2000,  the EPA  announced  it  would  proceed  with  the
development of  regulations  regarding  hazardous air  pollutants  from electric
power  plants.  The EPA  identified  mercury as the  hazardous  air pollutant of
greatest  concern.  The EPA  established  a schedule to propose  regulations  by
December 2003 and issue final  regulations  by December 2004. The future cost of
compliance with these regulations may be substantial.

          As a result of the Resource  Conservation and Recovery Act of 1976, as
amended,  and the  Toxic  Substances  Control  Act of 1976,  federal  and  state
hazardous  waste   regulations  have  been  promulgated.   Certain   fossil-fuel
combustion waste products,  such as coal ash, were exempted from hazardous waste
disposal  requirements  pending  the  EPA's  evaluation  of the need for  future
regulation.   The  EPA  has  issued  its  final  regulatory  determination  that
regulation of coal ash as a hazardous waste is  unnecessary.  In April 2000, the
EPA announced that it will develop  national  standards  regulating  disposal of
coal ash under its authority to regulate nonhazardous waste.

          Various   environmental   liabilities  have  been  recognized  on  the
Consolidated  Balance  Sheet as of December 31, 2001,  based on estimates of the
total costs of cleanup,  the Companies'  proportionate  responsibility  for such
costs and the  financial  ability of other  nonaffiliated  entities to pay.  The
Companies have been named as "potentially  responsible  parties" (PRPs) at waste
disposal sites which may require cleanup under the  Comprehensive  Environmental
Response,  Compensation  and Liability Act of 1980.  Allegations  of disposal of
hazardous substances at historical sites

<PAGE>



and the liability  involved,  are often  unsubstantiated and subject to dispute.
Federal law  provides  that all PRPs for a  particular  site be held liable on a
joint and  several  basis.  In  addition,  JCP&L  has  accrued  liabilities  for
environmental remediation of former manufactured gas plants in New Jersey; those
costs are being recovered by JCP&L through a  non-bypassable  societal  benefits
charge. The Companies have total accrued liabilities  aggregating  approximately
$60 million as of December 31, 2001. We do not believe environmental remediation
costs will have a material adverse effect on financial condition,  cash flows or
results of operations.

Legal Matters

          Various  lawsuits,  claims and  proceedings  related to  FirstEnergy's
normal business operations are pending against FirstEnergy and its subsidiaries.
The most significant are described below.

          Due to our merger  with GPU,  we own Unit 2 of the Three  Mile  Island
(TMI-2)  Nuclear  Plant.  As a result of the 1979  TMI-2  accident,  claims  for
alleged personal injury against JCP&L, Met-Ed, Penelec and GPU were filed in the
U.S.  District  Court for the Middle  District  of  Pennsylvania.  In 1996,  the
District Court granted a motion for summary  judgment filed by the GPU companies
and  dismissed  the ten initial  "test cases" which had been selected for a test
case trial, as well as all of the remaining  2,100 pending  claims.  In November
1999,  the U.S.  Court of Appeals for the Third  Circuit  affirmed  the District
Court's  dismissal  of the ten test cases,  but set aside the  dismissal  of the
additional  pending  claims,  remanding  them to the District  Court for further
proceedings.  Following  the  resolution  of judicial  proceedings  dealing with
admissible  evidence,  we have again requested summary judgment of the remaining
2,100 claims in the District  Court.  On January 15,  2002,  the District  Court
granted our motion.  On February  14,  2002,  the  plaintiffs  filed a notice of
appeal of this decision (see Note 6 - Other Legal Proceedings).  Although unable
to predict the outcome of this  litigation,  we believe  that any  liability  to
which we might be  subject by reason of the TMI-2  accident  will not exceed our
financial protection under the Price-Anderson Act.

          In July 1999, the Mid-Atlantic  states experienced a severe heat storm
which  resulted in power outages  throughout  the service areas of many electric
utilities,  including JCP&L. In an investigation  into the causes of the outages
and the reliability of the transmission and distribution systems of all four New
Jersey electric utilities,  the NJBPU concluded that there was not a prima facie
case demonstrating that, overall, JCP&L provided unsafe,  inadequate or improper
service to its customers.  Two class action lawsuits (subsequently  consolidated
into a single  proceeding)  were filed in New Jersey Superior Court in July 1999
against JCP&L,  GPU and other GPU companies  seeking  compensatory  and punitive
damages  arising  from  the  service  interruptions  of July  1999 in the  JCP&L
territory.  In May 2001,  the court denied  without  prejudice  the  defendant's
motion seeking  decertification of the class.  Discovery  continues in the class
action, but no trial date has been set. The judge has set a schedule under which
factual legal  discovery  would conclude in March 2002, and expert reports would
be  exchanged  by June 2002.  In October  2001,  the court held  argument on the
plaintiffs'  motion for partial summary  judgment,  which contends that JCP&L is
bound to several findings of the NJBPU investigation. The plaintiffs' motion was
denied  by the  Court  in  November  2001  and the  plaintiffs'  motion  seeking
permission  to file an appeal on this denial of their motion was rejected by the
New Jersey Appellate  Division.  We have also filed a motion for partial summary
judgment that is currently  pending before the Superior  Court. We are unable to
predict the outcome of these matters.

Other Commitments, Guarantees and Contingencies

          GPU  had  made  significant  investments  in  foreign  businesses  and
facilities through its GPU Electric and GPU Power subsidiaries. Although we will
attempt to mitigate our risks related to foreign investments, we face additional
risks  inherent in  operating  in such  locations,  including  foreign  currency
fluctuations.

          GPU  Electric,  through  its  subsidiary,  Midlands,  has a 40% equity
interest in a 586 MW power  project in Pakistan (the Uch Power  Project),  which
commenced  commercial  operations in October 2000. GPU Electric's  investment in
this  project as of December  31, 2001 was  approximately  $38  million,  plus a
guaranty  letter  of  credit of $3.6  million,  and its  share of the  projected
completion costs represents an additional $4.8 million commitment.  Cinergy (the
former  owner  of 50% of  Midlands  Electricity  plc)  agreed  to  fund up to an
aggregate  of  $20  million  of  the  required  capital  contributions  and  has
reimbursed  GPU Electric  $4.9  million  through  December  31, 2001,  leaving a
remaining  commitment  for future cash losses of up to $15.1  million.  Midlands
also has a 31% equity  interest in a 478 MW power  project in Turkey (the Trakya
Power Project).  Trakya is presently  engaged in a foreign  currency  conversion
issue with TETTAS (the state owned electricity purchaser).  Midlands established
a $16.5 million reserve for  non-recovery  relating to that issue as of December
31, 2001.  These  commitments  and  contingencies  associated with Midlands will
transfer to the new partnership  upon completion of the sale discussed in Note 2
- Merger, and we will be responsible for our lower proportionate interest.

          El Barranquilla,  a wholly owned subsidiary of GPU Power, is an equity
investor in Termobarranquilla S.A., Empresa de Servicios Publicos (TEBSA), which
owns a Colombian  independent power generation project. As of December 31, 2001,
GPU Power had an  investment  of  approximately  $109.4  million in TEBSA and is
committed,  under  certain  circumstances,  to make  additional  standby  equity
contributions of $21.3 million, which we have guaranteed.  The total outstanding
senior debt of the TEBSA  project is $315  million at  December  31,  2001.  The
lenders include the

<PAGE>


Overseas Private Investment Corporation,  US Export Import Bank and a commercial
bank syndicate. GPU had guaranteed the obligations of the operators of the TEBSA
project,  up to a maximum of $5.8  million  (subject  to  escalation)  under the
project's operations and maintenance agreement.

          GPU believed that various  events of default have  occurred  under the
loan agreements relating to the TEBSA project. In addition,  questions have been
raised as to the accuracy and  completeness  of information  provided to various
parties to the project in connection with the project's  formation.  We continue
to discuss these issues and related  matters with the project  lenders,  CORELCA
(the government owned Colombian  electric utility with an ownership  interest in
the project) and the Government of Colombia.

          Moreover,  in September  2001,  the DIAN (the  Colombian  national tax
authority) had presented TEBSA with a statement of charges alleging that certain
lease payments made under the Lease  Agreement  with Los Amigos Leasing  Company
(an indirect wholly owned  subsidiary of GPU Power) violated  Colombian  foreign
exchange regulations and were, therefore,  subject to substantial penalties. The
DIAN has calculated a statutory penalty amounting to approximately  $200 million
and gave TEBSA two months to respond to the  statement  of charges.  In November
2001,  TEBSA filed a formal  response  to this  statement  of charges.  TEBSA is
continuing  to review the DIAN's  position and has been advised by its Colombian
counsel that the DIAN's  position is without  substantial  legal  merit.  We are
unable to predict the outcome of these matters.
Significant Accounting Policies

          We prepare our  consolidated  financial  statements in accordance with
accounting  principles  generally accepted in the United States.  Application of
these  principles  often  require  a high  degree  of  judgment,  estimates  and
assumptions that affect our financial results.  All of our assets are subject to
their own specific  risks and  uncertainties  and are  continually  reviewed for
impairment.  Assets related to the  application of the policies  discussed below
are  similarly  reviewed  with their risks and  uncertainties  reflecting  these
specific factors. Our more significant accounting policies are described below:

Purchase Accounting - Acquisition of GPU

          Purchase  accounting requires judgment regarding the allocation of the
purchase  price  based on the fair  values  of the  assets  acquired  (including
intangible assets) and the liabilities  assumed. The fair values of the acquired
assets and assumed  liabilities for GPU were based  primarily on estimates.  The
more  significant  of these  included  the  estimation  of the fair value of the
international operations,  certain domestic operations and the fair value of the
pension and other postretirement benefit assets and liabilities. The preliminary
purchase price  allocations for the GPU acquisition are subject to adjustment in
2002 when  finalized.  The excess of the purchase  price over the estimated fair
values  of the  assets  acquired  and  liabilities  assumed  was  recognized  as
goodwill,  which  will be  reviewed  for  impairment  at least  annually.  As of
December 31, 2001,  we had $5.6 billion of goodwill  (excluding  the goodwill in
"Assets Pending Sale" on the Consolidated  Balance Sheet) that primarily relates
to our regulated services segment.

Regulatory Accounting

          Our regulated  services segment is subject to regulation that sets the
prices (rates) we are permitted to charge our customers  based on our costs that
the  regulatory  agencies  determine  we are  permitted  to  recover.  At times,
regulators  permit  the  future  recovery  through  rates of costs that would be
currently charged to expense by an unregulated company. This rate-making process
results in the recording of regulatory  assets based on anticipated  future cash
inflows. As a result of the changing regulatory framework in each state in which
we operate, a significant amount of regulatory assets have been recorded.  As of
December 31, 2001,  we had  regulatory  assets of $8.9 billion.  We  continually
review these assets to assess their ultimate  recoverability within the approved
regulatory  guidelines.  Impairment risk associated with these assets relates to
potentially adverse  legislative,  judicial or regulatory actions in the future.
As disclosed in Note 1 - Regulatory Plans, the full recovery of transition costs
for the Ohio EUOC is dependent on achieving 20% customer  shopping levels in any
twelve-month period by December 31, 2005.

Derivative Accounting

          Determination  of appropriate  accounting for derivative  transactions
requires the involvement of management representing operations, finance and risk
assessment.  In order to determine the  appropriate  accounting  for  derivative
transactions,  the  provisions of the contract need to be carefully  assessed in
accordance  with  the  authoritative   accounting  literature  and  management's
intended use of the derivative.  New authoritative  guidance  continues to shape
the  application  of  derivative  accounting.   Management's   expectations  and
intentions  are key factors in  determining  the  appropriate  accounting  for a
derivative  transaction and, as a result,  such expectations and intentions must
be documented. Derivative contracts that are determined to fall within the scope
of SFAS 133, as amended,  must be  recorded at their fair value.  Active  market
prices are not always  available to determine  the fair value of the later years
of a contract, requiring that various assumptions and estimates be used in the
valuation. We continually monitor our

<PAGE>


derivative contracts to determine if our activities,  expectations,  intentions,
assumptions  and  estimates  remain valid.  As part of our normal  operations we
enter into  significant  commodities  contracts,  which  increase  the impact of
derivative accounting judgments.

Revenue Recognition

           We follow the accrual method of accounting for revenues, recognizing
revenue for kilowatt-hour sales that have been delivered but not yet been billed
through the end of the year. The determination of unbilled revenues requires
management to make various estimated including:

          o  Net energy generated or purchased for retail load
          o  Losses of energy over distribution lines
          o  Mix of kilowatt-hour usage by residential, commercial and
             industrial customers
          o  Kilowatt-hour usage of customers receiving electricity from
             alternative suppliers

Recently Issued Accounting Standards

          The Financial  Accounting  Standards  Board (FASB)  approved SFAS 141,
"Business Combinations" and SFAS 142, "Goodwill and Other Intangible Assets," on
June 29, 2001. SFAS 141 requires all business combinations  initiated after June
30, 2001, to be accounted for using purchase  accounting.  The provisions of the
new standard  relating to the  determination  of goodwill  and other  intangible
assets  have  been  applied  to the GPU  merger,  which was  accounted  for as a
purchase  transaction,  and have not materially affected the accounting for this
transaction.  Under  SFAS 142,  amortization  of  existing  goodwill  will cease
January 1, 2002. Instead,  goodwill will be tested for impairment at least on an
annual  basis,  and no impairment  of goodwill is  anticipated  as a result of a
preliminary analysis.  Prior to the GPU merger,  FirstEnergy amortized about $57
million  ($.25 per share of common  stock) of  goodwill  annually.  There was no
goodwill  amortization  in  2001  associated  with  the  GPU  merger  under  the
provisions of the new standard.

          In July  2001,  the  FASB  issued  SFAS  143,  "Accounting  for  Asset
Retirement  Obligations." The new statement  provides  accounting  standards for
retirement obligations associated with tangible long-lived assets, with adoption
required  by  January  1,  2003.  SFAS 143  requires  that  the fair  value of a
liability for an asset retirement  obligation be recorded in the period in which
it is incurred. The associated asset retirement costs are capitalized as part of
the carrying amount of the long-lived asset. Over time the capitalized costs are
depreciated and the present value of the asset retirement  liability  increases,
resulting in a period expense. Upon retirement,  a gain or loss will be recorded
if the cost to  settle  the  retirement  obligation  differs  from the  carrying
amount. We are currently  assessing the new standard and have not yet determined
the impact on our financial statements.

          In  September  2001,  the FASB  issued SFAS 144,  "Accounting  for the
Impairment or Disposal of  Long-Lived  Assets."  SFAS 144  supersedes  SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of." The Statement  also  supersedes  the  accounting  and reporting
provisions of APB 30. Our adoption of this Statement, effective January 1, 2002,
will  result in our  accounting  for any  future  impairments  or  disposals  of
long-lived  assets  under the  provisions  of SFAS 144,  but will not change the
accounting   principles  used  in  previous  asset   impairments  or  disposals.
Application of SFAS 144 is not  anticipated to have a major impact on accounting
for impairments or disposal  transactions  compared to the prior  application of
SFAS 121 or APB 30.



<PAGE>
<TABLE>
<CAPTION>



                                                          FIRSTENERGY CORP.

                                                  CONSOLIDATED STATEMENTS OF INCOME



For the Years Ended December 31,                                                  2001         2000           1999
---------------------------------------------------------------------------------------------------------------------
                                                                              (In thousands, except per share amounts)
<S>                                                                           <C>            <C>           <C>
REVENUES:

   Electric utilities....................................................     $5,729,036     $5,421,668    $5,453,763
   Unregulated businesses................................................      2,270,326      1,607,293       865,884
                                                                              ----------     ----------    ----------
       Total revenues....................................................      7,999,362      7,028,961     6,319,647
                                                                              ----------     ----------    ----------

EXPENSES:
   Fuel and purchased power..............................................      1,421,525      1,110,845       984,941
   Purchased gas.........................................................        820,031        553,548       170,630
   Other operating expenses..............................................      2,727,794      2,378,296     2,146,629
   Provision for depreciation and amortization...........................        889,550        933,684       937,976
   General taxes.........................................................        455,340        547,681       544,052
                                                                              ----------     ----------    ----------
       Total expenses....................................................      6,314,240      5,524,054     4,784,228
                                                                              ----------     ----------    ----------

INCOME BEFORE INTEREST AND INCOME TAXES..................................      1,685,122      1,504,907     1,535,419
                                                                              ----------     ----------    ----------

NET INTEREST CHARGES:
   Interest expense......................................................        519,131        493,473       509,169
   Capitalized interest..................................................        (35,473)       (27,059)      (13,355)
   Subsidiaries' preferred stock dividends...............................         72,061         62,721        76,479
                                                                              ----------     ----------    ----------
       Net interest charges..............................................        555,719        529,135       572,293
                                                                              ----------     ----------    ----------

INCOME TAXES.............................................................        474,457        376,802       394,827
                                                                              ----------     ----------    ----------

INCOME BEFORE CUMULATIVE EFFECT OF A CHANGE
   IN ACCOUNTING.........................................................        654,946        598,970       568,299
                                                                              ----------     ----------    ----------

CUMULATIVE EFFECT OF ACCOUNTING CHANGE (NET OF
   INCOME TAX BENEFIT OF $5,839,000) (Note 1)............................         (8,499)            --            --
                                                                              ----------     ----------    ----------

NET INCOME...............................................................     $  646,447     $  598,970    $  568,299
                                                                              ==========     ==========    ==========

BASIC EARNINGS PER SHARE OF COMMON STOCK (Note 4C):
   Income before cumulative effect of accounting change..................          $2.85          $2.69         $2.50
   Cumulative effect of accounting change (Net of income taxes) (Note 1).           (.03)            --            --
                                                                                   -----          -----         -----
   Net income............................................................          $2.82          $2.69         $2.50
                                                                                   =====          =====         =====

   WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING...................        229,512        222,444       227,227
                                                                                 =======        =======       =======

DILUTED EARNINGS PER SHARE OF COMMON STOCK (Note 4C):
   Income before cumulative effect of accounting change..................          $2.84          $2.69         $2.50
   Cumulative effect of accounting change (Net of income taxes) (Note 1).           (.03)            --            --
                                                                                   -----          -----         -----
   Net income............................................................          $2.81          $2.69         $2.50
                                                                                   =====          =====         =====

   WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING.................        230,430        222,726       227,299
                                                                                 =======        =======       =======

DIVIDENDS DECLARED PER SHARE OF COMMON STOCK.............................          $1.50          $1.50         $1.50
                                                                                   =====          =====         =====

<FN>


The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.

</FN>
</TABLE>



<PAGE>
<TABLE>
<CAPTION>


                                FIRSTENERGY CORP.

                           CONSOLIDATED BALANCE SHEETS


As of December 31,                                                                             2001           2000
---------------------------------------------------------------------------------------------------------------------
                                                                                                  (In thousands)
                                         ASSETS
<S>                                                                                       <C>             <C>
CURRENT ASSETS:

   Cash and cash equivalents..........................................................    $   220,178     $    49,258
   Receivables-
     Customers (less accumulated provisions of $65,358,000 and $32,251,000,
       respectively, for uncollectible accounts)......................................      1,074,664         541,924
     Other (less accumulated provisions of $7,947,000 and $4,035,000,
       respectively, for uncollectible accounts)......................................        473,550         376,525
   Materials and supplies, at average cost-
     Owned............................................................................        256,516         171,563
     Under consignment................................................................        141,002         112,155
   Prepayments and other..............................................................        336,610         189,869
                                                                                          -----------     -----------
                                                                                            2,502,520       1,441,294
                                                                                          -----------     -----------

ASSETS PENDING SALE (Note 2).........................................................       3,418,225              --
                                                                                          -----------     -----------

PROPERTY, PLANT AND EQUIPMENT:
   In service.........................................................................     19,981,749      12,417,684
   Less--Accumulated provision for depreciation.......................................      8,161,022       5,263,483
                                                                                          -----------     -----------
                                                                                           11,820,727       7,154,201
   Construction work in progress......................................................        607,702         420,875
                                                                                          -----------     -----------
                                                                                           12,428,429       7,575,076
                                                                                          -----------     -----------
INVESTMENTS:
   Capital trust investments (Note 3).................................................      1,166,714       1,223,794
   Nuclear plant decommissioning trusts...............................................      1,014,234         584,288
   Letter of credit collateralization (Note 3)........................................        277,763         277,763
   Pension investments................................................................        273,542         200,178
   Other..............................................................................        898,311         468,879
                                                                                          -----------     -----------
                                                                                            3,630,564       2,754,902
                                                                                          -----------     -----------
DEFERRED CHARGES:
   Regulatory assets..................................................................      8,912,584       3,727,662
   Goodwill...........................................................................      5,600,918       2,088,770
   Other..............................................................................        858,273         353,590
                                                                                          -----------     -----------
                                                                                           15,371,775       6,170,022
                                                                                          -----------     -----------
                                                                                          $37,351,513     $17,941,294
                                                                                          ===========     ===========
                   LIABILITIES AND CAPITALIZATION

CURRENT LIABILITIES:
   Currently payable long-term debt and preferred stock...............................    $ 1,867,657     $   536,482
   Short-term borrowings (Note 5).....................................................        614,298         699,765
   Accounts payable...................................................................        704,184         478,661
   Accrued taxes......................................................................        418,555         409,640
   Other..............................................................................      1,064,763         469,257
                                                                                          -----------     -----------
                                                                                            4,669,457       2,593,805
                                                                                          -----------     -----------

LIABILITIES RELATED TO ASSETS PENDING SALE (Note 2)..................................       2,954,753              --
                                                                                          -----------     -----------

CAPITALIZATION (See Consolidated Statements of Capitalization):
   Common stockholders' equity........................................................      7,398,599       4,653,126
   Preferred stock of consolidated subsidiaries--
     Not subject to mandatory redemption..............................................        480,194         648,395
     Subject to mandatory redemption..................................................         65,406          41,105
   Subsidiary-obligated mandatorily redeemable preferred securities (Note 4F).........        529,450         120,000
   Long-term debt.....................................................................     11,433,313       5,742,048
                                                                                          -----------     -----------
                                                                                           19,906,962      11,204,674
                                                                                          -----------     -----------
DEFERRED CREDITS:
   Accumulated deferred income taxes..................................................      2,684,219       2,094,107
   Accumulated deferred investment tax credits........................................        260,532         241,005
   Nuclear plant decommissioning costs................................................      1,201,599         598,985
   Power purchase contract loss liability.............................................      3,566,531              --
   Other postretirement benefits......................................................        838,943         544,541
   Other..............................................................................      1,268,517         664,177
                                                                                          -----------     -----------
                                                                                            9,820,341       4,142,815
                                                                                          -----------     -----------
COMMITMENTS, GUARANTEES AND CONTINGENCIES (Notes 3 and 6).............................
                                                                                          -----------     -----------
                                                                                          $37,351,513     $17,941,294
                                                                                          ===========     ===========

<FN>


The accompanying Notes to Consolidated Financial Statements are an integral part
of these balance sheets.

</FN>
</TABLE>


<PAGE>
<TABLE>
<CAPTION>


                                                          FIRSTENERGY CORP.

                                              CONSOLIDATED STATEMENTS OF CAPITALIZATION


As of December 31,                                                                                           2001          2000
---------------------------------------------------------------------------------------------------------------------------------
                                                                               (Dollars in thousands, except per share amounts)
<S>                                                                                                       <C>          <C>
COMMON STOCKHOLDERS' EQUITY:
 Common stock, $0.10 par value - authorized 375,000,000 shares-
   297,636,276 and 224,531,580 shares outstanding, respectively.........................                  $    29,764  $    22,453
 Other paid-in capital..................................................................                    6,113,260    3,531,821
 Accumulated other comprehensive income (loss) (Note 4H)................................                     (169,003)         593
 Retained earnings (Note 4A)............................................................                    1,521,805    1,209,991
 Unallocated employee stock ownership plan common stock-
   5,117,375 and 5,952,032 shares, respectively (Note 4B)...............................                      (97,227)    (111,732)
                                                                                                          -----------  -----------
   Total common stockholders' equity....................................................                    7,398,599    4,653,126
                                                                                                          -----------  -----------
<CAPTION>

                                                 Number of Shares             Optional
                                                   Outstanding             Redemption Price
                                                 ----------------       ---------------------
                                                 2001        2000       Per Share   Aggregate
                                                 ----        ----       ---------   ---------
<S>                                          <C>          <C>            <C>       <C>
PREFERRED STOCK OF CONSOLIDATED
SUBSIDIARIES (Note 4D):
Ohio Edison Company
Cumulative, $100 par value-
Authorized 6,000,000 shares
 Not Subject to Mandatory Redemption:
   3.90%..............................         152,510      152,510      $103.63   $ 15,804                    15,251       15,251
   4.40%..............................         176,280      176,280       108.00     19,038                    17,628       17,628
   4.44%..............................         136,560      136,560       103.50     14,134                    13,656       13,656
   4.56%..............................         144,300      144,300       103.38     14,917                    14,430       14,430
                                             ---------    ---------                --------               -----------  -----------
                                               609,650      609,650                  63,893                    60,965       60,965
                                             ---------    ---------                --------               -----------  -----------

Cumulative, $25 par value-
Authorized 8,000,000 shares
 Not Subject to Mandatory Redemption:
   7.75%..............................       4,000,000    4,000,000        25.00    100,000                   100,000      100,000
                                             ---------    ---------                --------               -----------  -----------
   Total Not Subject to
   Mandatory Redemption...............       4,609,650    4,609,650                $163,893                   160,965      160,965
                                             =========    =========                ========               -----------  -----------

Cumulative, $100 par value-
 Subject to Mandatory Redemption:
   8.45%..............................              --       50,000           --   $     --                        --        5,000
 Redemption Within One Year...........                                                                             --       (5,000)
                                             ---------    ---------                --------               -----------  -----------
    Total Subject to Mandatory Redemption           --       50,000                $     --                        --           --
                                             =========    =========                ========               -----------  -----------
Pennsylvania Power Company
Cumulative, $100 par value-
Authorized 1,200,000 shares
 Not Subject to Mandatory Redemption:
   4.24%..............................          40,000       40,000       103.13   $  4,125                     4,000        4,000
   4.25%..............................          41,049       41,049       105.00      4,310                     4,105        4,105
   4.64%..............................          60,000       60,000       102.98      6,179                     6,000        6,000
   7.75%..............................         250,000      250,000           --         --                    25,000       25,000
                                             ---------    ---------                --------               -----------  -----------
   Total Not Subject to Mandatory
   Redemption.........................         391,049      391,049                $ 14,614                    39,105       39,105
                                             =========    =========                ========               -----------  -----------

 Subject to Mandatory Redemption (Note 4E):
   7.625%.............................         150,000      150,000       104.58   $ 15,687                    15,000       15,000
 Redemption Within One Year...........                                                                           (750)          --
                                             ---------    ---------                --------               -----------  -----------
   Total Subject to Mandatory Redemption       150,000     150,000                 $ 15,687                    14,250       15,000
                                             =========    =========                ========               -----------  -----------
Cleveland Electric Illuminating Company
Cumulative, without par value-
Authorized 4,000,000 shares
 Not Subject to Mandatory Redemption:
   $  7.40 Series A...................         500,000      500,000       101.00   $ 50,500                    50,000       50,000
   $  7.56 Series B...................         450,000      450,000       102.26     46,017                    45,071       45,071
   Adjustable Series L................         474,000      474,000       100.00     47,400                    46,404       46,404
   $42.40 Series T....................         200,000      200,000       500.00    100,000                    96,850       96,850
                                             ---------    ---------                --------               -----------  -----------
                                             1,624,000    1,624,000                 243,917                   238,325      238,325
 Redemption Within One Year (Note 4D).                                                                        (96,850)          --
                                             ---------    ---------                --------               -----------  -----------
   Total Not Subject to Mandatory
   Redemption.........................       1,624,000    1,624,000                $243,917                   141,475      238,325
                                             =========    =========                ========               -----------  -----------

 Subject to Mandatory Redemption (Note 4E):
   $  7.35 Series C...................          70,000       80,000       101.00   $  7,070                     7,030        8,041
   $91.50 Series Q....................              --       10,716           --         --                        --       10,716
   $88.00 Series R....................              --       50,000           --         --                        --       51,128
   $90.00 Series S....................          17,750       36,500           --         --                    17,268       36,686
                                             ---------    ---------                --------               -----------  -----------
                                                87,750      177,216                   7,070                    24,298      106,571
 Redemption Within One Year...........                                                                        (18,010)     (80,466)
                                             ---------    ---------                --------               -----------  -----------
   Total Subject to Mandatory Redemption        87,750      177,216                $  7,070                     6,288       26,105
                                             =========    =========                ========               -----------  -----------

</TABLE>


<PAGE>
<TABLE>
<CAPTION>


                                                          FIRSTENERGY CORP.

                                         CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)


As of December 31,                                                                                          2001           2000
----------------------------------------------------------------------------------------------------------------------------------
                                                                               (Dollars in thousands, except per share amounts)

                                                Number of Shares              Optional
                                                   Outstanding             Redemption Price
                                                ----------------        ---------------------
                                                2001       2000         Per Share   Aggregate
                                                ----       ----         ---------   ---------
<S>                                          <C>          <C>            <C>       <C>                    <C>          <C>
PREFERRED STOCK OF CONSOLIDATED
SUBSIDIARIES (Cont'd)
Toledo Edison Company
Cumulative, $100 par value-
Authorized 3,000,000 shares
 Not Subject to Mandatory Redemption:
   $  4.25............................         160,000      160,000      $104.63   $ 16,740               $    16,000  $    16,000
   $  4.56............................          50,000       50,000       101.00      5,050                     5,000        5,000
   $  4.25............................         100,000      100,000       102.00     10,200                    10,000       10,000
   $  8.32............................         100,000      100,000       102.46     10,246                    10,000       10,000
   $  7.76............................         150,000      150,000       102.44     15,366                    15,000       15,000
   $  7.80............................         150,000      150,000       101.65     15,248                    15,000       15,000
   $10.00.............................         190,000      190,000       101.00     19,190                    19,000       19,000
                                             ---------    ---------                --------               -----------  -----------
                                               900,000      900,000                  92,040                    90,000       90,000
 Redemption Within One Year (Note 4D).                                                                        (59,000)          --
                                             ---------    ---------                --------               -----------  -----------
                                               900,000      900,000                  92,040                    31,000       90,000
                                             ---------    ---------                --------               -----------  -----------
Cumulative, $25 par value-
Authorized 12,000,000 shares
 Not Subject to Mandatory Redemption:
   $2.21..............................       1,000,000    1,000,000        25.25     25,250                    25,000       25,000
    2.365.............................       1,400,000    1,400,000        27.75     38,850                    35,000       35,000
   Adjustable Series A................       1,200,000    1,200,000        25.00     30,000                    30,000       30,000
   Adjustable Series B................       1,200,000    1,200,000        25.00     30,000                    30,000       30,000
                                             ---------    ---------                --------               -----------  -----------
                                             4,800,000    4,800,000                 124,100                   120,000      120,000
                                             ---------    ---------                --------
 Redemption Within One Year (Note 4D).                                                                        (25,000)          --
                                             ---------    ---------                --------               -----------  -----------
                                             4,800,000    4,800,000                 124,100                    95,000      120,000
                                             ---------    ---------                --------               -----------  -----------
   Total Not Subject to Mandatory
     Redemption.......................       5,700,000    5,700,000                $216,140                   126,000      210,000
                                             =========    =========                ========               -----------  -----------

Jersey Central Power & Light Company
Cumulative, $100 stated value-
Authorized 15,600,000 shares
 Not Subject to Mandatory Redemption:
   4.00% Series.......................         125,000           --       106.50   $ 13,313                    12,649           --
                                             =========    =========                ========               -----------  -----------

 Subject to Mandatory Redemption (Note 4E):
   8.65% Series J.....................         250,001           --       101.30   $ 25,325                    26,750           --
   7.52% Series K.....................         265,000           --       103.76     27,496                    28,951           --
                                             ---------    ---------                --------               -----------  -----------
                                               515,001           --                  52,821                    55,701           --
 Redemption Within One Year...........                                                                        (10,833)          --
                                             ---------    ---------                --------               -----------  -----------
   Total Subject to Mandatory Redemption       515,001           --                $ 52,821                    44,868           --
                                             =========    =========                ========               -----------  -----------

SUBSIDIARY-OBLIGATED MANDATORILY
REDEEMABLE PREFERRED SECURITIES OF
SUBSIDIARY TRUST OR LIMITED PARTNERSHIP
HOLDING SOLELY SUBORDINATED DEBENTURES
OF SUBSIDIARIES (NOTE 4F):

Ohio Edison Co.
Cumulative, $25 stated value-
Authorized 4,800,000 shares
   9.00%................................     4,800,000    4,800,000        25.00   $120,000                   120,000      120,000
                                             =========    =========                ========               -----------  -----------

Cleveland Electric Illuminating Co.
Cumulative, $25 stated value-
Authorized 4,000,000 shares
   9.00%................................     4,000,000           --           --   $     --                   100,000           --
                                             =========    =========                ========               -----------  -----------

Jersey Central Power & Light Co.
Cumulative, $25 stated value-
Authorized 5,000,000 shares
   8.56%................................     5,000,000           --        25.00   $125,000                   125,250           --
                                             =========   ==========                ========               -----------  -----------

Metropolitan Edison Co.
Cumulative, $25 stated value-
Authorized 4,000,000 shares
   7.35%................................     4,000,000           --           --   $     --                    92,200           --
                                             =========    =========                ========               -----------  -----------

Pennsylvania Electric Co.
Cumulative, $25 stated value-
Authorized 4,000,000 shares
   7.34%................................     4,000,000           --           --   $     --                    92,000           --
                                             =========    =========                ========               -----------  -----------

</TABLE>


<PAGE>
<TABLE>
<CAPTION>


                                                          FIRSTENERGY CORP.

                                         CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)



LONG-TERM DEBT (Note 4G) (Interest rates reflect weighted average rates)                                (In thousands)
---------------------------------------------------------------------------------------------------------------------------------
                        FIRST MORTGAGE BONDS           SECURED NOTES               UNSECURED NOTES               TOTAL
---------------------------------------------------------------------------------------------------------------------------------
As of December 31,          2001        2000              2001       2000              2001       2000       2001         2000
                            ----        ----              ----       ----              ----       ----       ----         ----
<S>                <C>   <C>         <C>         <C>   <C>        <C>         <C>   <C>         <C>       <C>          <C>
Ohio Edison Co. -
 Due 2001-2006     7.89% $  509,265  $  509,265  7.60% $  227,122 $  235,838  4.28% $  441,725  $541,725
 Due 2007-2011       --          --          --  7.22%     10,253      4,336   --           --        --
 Due 2012-2016       --          --          --  5.17%     59,000     59,000   --           --        --
 Due 2017-2021       --          --          --  7.01%     60,443    129,943   --           --        --
 Due 2022-2026     7.99%    219,460     219,460    --          --         --   --           --        --
 Due 2027-2031       --          --          --  3.72%    249,634    180,134   --           --        --
 Due 2032-2036       --          --          --  2.63%     71,900     71,900   --           --        --
                         ----------  ----------        ---------- ----------        ----------  --------
Total-Ohio Edison           728,725     728,725           678,352    681,151           441,725   541,725  $ 1,848,802  $ 1,951,601
                         ----------  ----------        ---------- ----------        ----------  --------  -----------  -----------

Cleveland Electric
Illuminating Co. -
 Due 2001-2006     8.53%    595,000     595,000  5.84%    593,175    384,680  5.58%     27,700    27,700
 Due 2007-2011     6.86%    125,000     125,000  7.29%    271,640    271,640   --           --        --
 Due 2012-2016       --          --          --  8.00%     78,700    118,535   --           --        --
 Due 2017-2021       --          --          --  7.36%    440,560    560,855   --           --        --
 Due 2022-2026     9.00%    150,000     150,000  7.64%    218,950    218,950   --           --        --
 Due 2027-2031       --          --          --  5.38%      5,993    110,888   --           --        --
                         ----------  ----------        ---------- ----------        ----------  --------  -----------  -----------
Total-Cleveland Electric    870,000     870,000         1,609,018  1,665,548            27,700    27,700    2,506,718    2,563,248
                         ----------  ----------        ---------- ----------        ----------  --------  -----------  -----------

Toledo Edison Co. -
 Due 2001-2006     7.90%    179,125     179,525  6.40%    228,700    190,400  7.25%    226,100   226,130
 Due 2007-2011       --          --          --  7.13%     30,000     30,000 10.00%        790       790
 Due 2012-2016       --          --          --    --          --         --   --           --        --
 Due 2017-2021       --          --          --  8.14%    129,000    129,000   --           --        --
 Due 2022-2026       --          --          --  7.55%     50,700    118,000   --           --        --
 Due 2027-2031       --          --          --  5.90%     13,851     13,851   --           --        --
 Due 2032-2036       --          --          --  2.20%     30,900     30,900   --           --        --
                         ----------  ----------        ---------- ----------        ----------  --------  -----------  -----------
Total-Toledo Edison         179,125     179,525           483,151    512,151           226,890   226,920      889,166      918,596
                         ----------  ----------        ---------- ----------        ----------  --------  -----------  -----------

Pennsylvania Power Co. -
 Due 2001-2006     7.19%     79,370      80,344  3.02%     10,300         --  5.90%      5,200     5,200
 Due 2007-2011     9.74%      4,870       4,870    --          --         --   --           --        --
 Due 2012-2016     9.74%      4,870       4,870  5.40%      1,000      1,000   --           --        --
 Due 2017-2021     9.74%      2,955       2,955  3.78%     59,807     59,807   --           --        --
 Due 2022-2026     8.33%     33,750      33,750  6.15%     12,700     12,700   --           --        --
 Due 2027-2031       --          --          --  6.04%     37,672     47,972   --           --        --
                         ----------  ----------        ---------- ----------        ----------  --------  -----------  -----------
Total-Penn Power            125,815     126,789           121,479    121,479             5,200     5,200      252,494      253,468
                         ----------  ----------        ---------- ----------        ----------  --------  -----------  -----------

Jersey Central Power & Light Co. -
 Due 2001-2006     7.14%    500,945          --  6.45%    150,000         --  7.69%         86        --
 Due 2007-2011     7.81%     45,355          --    --          --         --  7.69%        124        --
 Due 2012-2016     7.10%     12,200          --    --          --         --  7.69%        180        --
 Due 2017-2021     9.20%     50,000          --    --          --         --  7.69%        260        --
 Due 2022-2026     7.68%    485,000          --    --          --         --  7.69%        377        --
 Due 2027-2031       --          --          --    --          --         --  7.69%        546        --
 Due 2032-2036       --          --          --    --          --         --  7.69%        790        --
 Due 2037-2041       --          --          --    --          --         --  7.69%        635        --
                         ----------  ----------        ---------- ----------        ----------  --------  -----------  -----------
Total-Jersey Central      1,093,500          --           150,000         --             2,998        --    1,246,498           --
                         ----------  ----------        ---------- ----------        ----------  --------  -----------  -----------

Metropolitan Edison Co. -
 Due 2001-2006     7.14%    261,740          --  5.72%    100,000         --  7.69%        171        --
 Due 2007-2011     6.00%      6,960          --    --          --         --  7.69%        248        --
 Due 2012-2016       --          --          --    --          --         --  7.69%        359        --
 Due 2017-2021     6.10%     28,500          --    --          --         --  7.69%        521        --
 Due 2022-2026     8.05%    180,000          --    --          --         --  7.69%        754        --
 Due 2027-2031     5.95%     13,690          --    --          --         --  7.69%      1,092        --
 Due 2032-2036       --          --          --    --          --         --  7.69%      1,581        --
 Due 2037-2041       --          --          --    --          --         --  7.69%      1,271        --
                         ----------  ----------        ---------- ----------        ----------  --------  -----------  -----------

Total-Metropolitan Edison   490,890          --           100,000         --             5,997        --      596,887           --
                         ----------  ----------        ---------- ----------        ----------  --------  -----------  -----------


</TABLE>


<PAGE>
<TABLE>
<CAPTION>


                                                          FIRSTENERGY CORP.

                                         CONSOLIDATED STATEMENTS OF CAPITALIZATION (Cont'd)



LONG-TERM DEBT (Interest rates reflect weighted average rates) (Cont'd)                                 (In thousands)

                  FIRST MORTGAGE BONDS           SECURED NOTES             UNSECURED NOTES               TOTAL
----------------------------------------------------------------------------------------------------------------------------------
As of December 31,           2001       2000             2001        2000              2001       2000       2001         2000
                             ----       ----             ----        ----              ----       ----       ----         ----
<S>                <C>   <C>         <C>           <C> <C>        <C>         <C>   <C>         <C>        <C>          <C>
Pennsylvania
 Electric Co. -
   Due 2001-2006   6.13% $    1,025  $       --    --  $       -- $       --  6.02% $  183,086  $     --
   Due 2007-2011   5.44%     27,395          --    --          --         --  6.55%    135,124        --
   Due 2012-2016     --          --          --    --          --         --  7.69%        180        --
   Due 2017-2021   5.80%     20,000          --    --          --         --  6.63%    125,260        --
   Due 2022-2026   6.05%     25,000          --    --          --         --  7.69%        377        --
   Due 2027-2031     --          --          --    --          --         --  7.69%        546        --
   Due 2032-2036     --          --          --    --          --         --  7.69%        790        --
   Due 2037-2041     --          --          --    --          --         --  7.69%        635        --
                         ----------  ----------        ---------- ----------        ----------  --------  -----------  -----------
  Total-Pennsylvania
   Electric                  73,420          --               --          --           445,998        --  $   519,418  $        --
                         ----------  ----------        ---------- ----------        ----------  --------  -----------  -----------

FirstEnergy Corp. -
   Due 2001-2006     --          --          --    --          --         --  5.59%  1,550,000        --
   Due 2007-2011     --          --          --    --          --         --  6.45%  1,500,000        --
   Due 2012-2016     --          --          --    --          --         --   --         --          --
   Due 2017-2021     --          --          --    --          --         --   --         --          --
   Due 2022-2026     --          --          --    --          --         --   --         --          --
   Due 2027-2031     --          --          --    --          --         --  7.38%  1,500,000        --
                         ----------  ----------        ---------- ----------        ----------  --------  -----------  -----------
Total-FirstEnergy               --           --               --          --         4,550,000        --    4,550,000           --
                         ----------  ----------        ---------- ----------        ----------  --------  -----------  -----------


OES Fuel                         --          --  2.72%     81,515     91,620   --           --        --       81,515       91,620
AFN Finance Co. No. 1            --          --  4.18%     15,000         --   --           --        --       15,000           --
AFN Finance Co. No. 3            --          --  4.18%      4,000         --   --           --        --        4,000           --
Bay Shore Power                  --          --  6.23%    145,400    147,500   --           --        --      145,400      147,500
MARBEL Energy Corp.              --          --    --          --         --  4.72%        569       638          569          638
Facilities Services Group        --          --  6.12%     15,735     17,601   --           --        --       15,735       17,601
FirstEnergy Properties           --          --  7.89%      9,902         --   --           --        --        9,902           --
Warrenton River Terminal         --          --  6.00%        776         --   --           --        --          776           --
GPU Capital*                     --          --    --          --         --  6.69%  1,629,582        --    1,629,582           --
GPU Power                        --          --  7.42%    239,373         -- 13.50%     56,048        --      295,421           --
                         ----------  ----------        ---------- ----------        ----------  --------  -----------  -----------
Total                    $3,561,475  $1,905,039        $3,653,701 $3,237,050        $7,392,707  $802,183   14,607,883    5,944,272
                         ==========  ==========        ========== ==========        ==========  ========  -----------  -----------
Capital lease obligations.....................................................................                 19,390      163,242
                                                                                                          -----------  -----------
Net unamortized premium on debt*..............................................................                213,834       85,550
                                                                                                          -----------  -----------
Long-term debt due within one year*..........................................................              (1,975,755)    (451,016)
                                                                                                          -----------  -----------
Total long-term debt*.........................................................................             12,865,352    5,742,048
                                                                                                          -----------  -----------
TOTAL CAPITALIZATION*                                                                                     $21,339,001  $11,204,674
----------------------------------------------------------------------------------------------------------------------------------

<FN>


* 2001 includes amounts in "Liabilities Related to Assets Pending Sale" on the
  Consolidated Balance Sheet as of December 31, 2001.

The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.

</FN>
</TABLE>



<PAGE>
<TABLE>
<CAPTION>

                                                          FIRSTENERGY CORP.

                                       CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS' EQUITY

                                                                                       Accumulated             Unallocated
                                                                            Other        Other                    ESOP
                                     Comprehensive     Number      Par     Paid-In    Comprehensive  Retained    Common
                                        Income       of Shares    Value    Capital    Income (Loss)  Earnings     Stock
                                     -------------   ---------    -----    -------    -------------  --------  -----------
                                                                     (Dollars in thousands)
<S>                                     <C>         <C>          <C>      <C>         <C>           <C>         <C>
Balance, January 1, 1999............                237,069,087  $23,707  $3,846,513  $    (439)    $  718,409  $(139,032)
   Net income.......................    $568,299                                                       568,299
   Minimum liability for unfunded
     retirement benefits, net of
     $160,000 of income taxes.......         244                                            244
                                        --------
   Comprehensive income.............    $568,543
                                        ========
   Reacquired common stock..........                 (4,614,800)    (462)   (129,671)
   Centerior acquisition adjustment.                                            (468)
   Allocation of ESOP shares........                                           6,001                                12,256
   Cash dividends on common stock...                                                                  (341,467)
--------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 1999..........                232,454,287   23,245   3,722,375       (195)       945,241    (126,776)
   Net income.......................    $598,970                                                       598,970
   Minimum liability for unfunded
     retirement benefits, net of
     ($85,000) of income taxes......        (134)                                          (134)
   Unrealized gain on investment in
     securities available for sale..         922                                            922
                                        --------
   Comprehensive income.............    $599,758
                                        ========
   Reacquired common stock..........                 (7,922,707)    (792)   (194,210)
   Allocation of ESOP shares........                                           3,656                                15,044
   Cash dividends on common stock...                                                                  (334,220)
--------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2000..........                224,531,580   22,453   3,531,821        593      1,209,991    (111,732)
   GPU acquisition..................                 73,654,696    7,366   2,586,097
   Net income.......................    $646,447                                                       646,447
   Minimum liability for unfunded
     retirement benefits, net of
     $(182,000) of income taxes....         (268)                                          (268)
   Unrealized loss on derivative hedges,
     net of $(116,521,000) of income
     taxes                              (169,408)                                      (169,408)
   Unrealized gain on investments, net
     of $56,000 of income taxes.....          81                                             81
   Unrealized currency translation
     adjustments, net of $(1,000) of
     income taxes                             (1)                                            (1)
                                        --------
   Comprehensive income.............    $476,851
                                        ========
   Reacquired common stock..........                   (550,000)     (55)    (15,253)
   Allocation of ESOP shares........                                          10,595                                14,505
   Cash dividends on common stock...                                                                  (334,633)
--------------------------------------------------------------------------------------------------------------------------
Balance, December 31, 2001..........                297,636,276  $29,764  $6,113,260  $(169,003)    $1,521,805    $(97,227)
==========================================================================================================================

<FN>

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

</FN>

</TABLE>


<TABLE>
<CAPTION>


                                             CONSOLIDATED STATEMENTS OF PREFERRED STOCK

                                                    Not Subject to                Subject to
                                                 Mandatory Redemption        Mandatory Redemption
                                                 --------------------        --------------------
                                                               Par or                      Par or
                                                  Number       Stated         Number       Stated
                                                 of Shares     Value         of Shares     Value
                                                 ---------     ------        ---------     -----
                                                               (Dollars in thousands)

               <S>                              <C>           <C>            <C>          <C>
                Balance, January 1, 1999        12,442,699    $660,195       5,379,044    $334,864
                  Redemptions-
                   7.64%  Series                   (60,000)     (6,000)
                   8.00%  Series                   (58,000)     (5,800)
                   8.45%  Series                                               (50,000)     (5,000)
                   $ 7.35 Series C                                             (10,000)     (1,000)
                   $88.00 Series E                                              (3,000)     (3,000)
                   $91.50 Series Q                                             (10,714)    (10,714)
                   $90.00 Series S                                             (18,750)    (18,750)
                   $9.375 Series                                               (16,900)     (1,690)
--------------------------------------------------------------------------------------------------
                Balance, December 31, 1999      12,324,699     648,395       5,269,680     294,710
                  Redemptions-
                   8.45%  Series                                               (50,000)     (5,000)
                   $ 7.35 Series C                                             (10,000)     (1,000)
                   $88.00 Series E                                              (3,000)     (3,000)
                   $91.50 Series Q                                             (10,714)    (10,714)
                   $90.00 Series S                                             (18,750)    (18,750)
                  Amortization of fair market
                    value adjustments-
                   $ 7.35 Series C                                                             (69)
                   $88.00 Series R                                                          (3,872)
                   $90.00 Series S                                                          (5,734)
                -----------------------------------------------------------------------------------
                Balance, December 31, 2000      12,324,699     648,395       5,177,216     246,571
                  GPU acquisition                  125,000      12,649      13,515,001     365,151
                  Issues-
                   9.00%  Series                                             4,000,000     100,000
                  Redemptions-
                   8.45%  Series                                               (50,000)     (5,000)
                   $ 7.35 Series C                                             (10,000)     (1,000)
                   $88.00 Series R                                             (50,000)    (50,000)
                   $91.50 Series Q                                             (10,716)    (10,716)
                   $90.00 Series S                                             (18,750)    (18,750)
                  Amortization of fair market
                    value adjustments-
                   $ 7.35 Series C                                                             (11)
                   $88.00 Series R                                                          (1,128)
                   $90.00 Series S                                                            (668)
                -----------------------------------------------------------------------------------
                Balance, December 31, 2001      12,449,699    $661,044      22,552,751    $624,449
                ===================================================================================
<FN>


The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.

</FN>
</TABLE>


<PAGE>
<TABLE>
<CAPTION>



                                FIRSTENERGY CORP.

                      CONSOLIDATED STATEMENTS OF CASH FLOWS



For the Years Ended December 31,                                         2001             2000              1999
--------------------------------------------------------------------------------------------------------------------
                                                                                       (In thousands)
<S>                                                                   <C>              <C>               <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income......................................................      $  646,447       $  598,970        $  568,299
Adjustments to reconcile net income to net
   cash from operating activities:
     Provision for depreciation and amortization................         889,550          933,684           937,976
     Nuclear fuel and lease amortization........................          98,178          113,330           104,928
     Other amortization, net....................................         (11,927)         (11,635)          (10,730)
     Deferred costs recoverable as regulatory assets............         (31,893)              --                --
     Deferred income taxes, net.................................          31,625          (79,429)          (45,054)
     Investment tax credits, net................................         (22,545)         (30,732)          (19,661)
     Cumulative effect of accounting change.....................          14,338               --                --
     Receivables................................................          53,099         (150,520)         (203,567)
     Materials and supplies.....................................         (50,052)         (29,653)           19,631
     Accounts payable...........................................         (84,572)         118,282            82,578
     Other......................................................        (250,564)          45,529            53,906
                                                                      ----------       ----------        ----------
       Net cash provided from operating activities..............       1,281,684        1,507,826         1,488,306
                                                                      ----------       ----------        ----------

CASH FLOWS FROM FINANCING ACTIVITIES:
New Financing-
   Preferred stock..............................................          96,739               --                --
   Long-term debt...............................................       4,338,080          307,512           364,832
   Short-term borrowings, net...................................              --          281,946           163,327
Redemptions and Repayments-
   Common stock.................................................          15,308          195,002           130,133
   Preferred stock..............................................          85,466           38,464            52,159
   Long-term debt...............................................         394,017          901,764           847,006
   Short-term borrowings, net...................................       1,641,484               --                --
Common Stock Dividend Payments..................................         334,633          334,220           341,467
                                                                      ----------       ----------        ----------
       Net cash provided from (used for) financing activities...       1,963,911         (879,992)         (842,606)
                                                                      ----------       ----------        ----------

CASH FLOWS FROM INVESTING ACTIVITIES:
GPU acquisition, net of cash....................................       2,013,218               --                --
Property additions..............................................         852,449          587,618           624,901
Cash investments................................................         (24,518)         (17,449)          (41,213)
Other...........................................................         233,526          120,195            28,022
                                                                      ----------       ----------        ----------
       Net cash used for investing activities...................       3,074,675          690,364           611,710
                                                                      ----------       ----------        ----------
Net increase (decrease) in cash and cash equivalents............         170,920          (62,530)           33,990
Cash and cash equivalents at beginning of year..................          49,258          111,788            77,798
                                                                      ----------       ----------        ----------
Cash and cash equivalents at end of year*.......................      $  220,178       $   49,258        $  111,788
                                                                      ==========       ==========        ==========

SUPPLEMENTAL CASH FLOWS INFORMATION:
Cash Paid During the Year-
   Interest (net of amounts capitalized)........................      $  425,737       $  485,374        $  520,072
   Income taxes.................................................      $  433,640       $  512,182        $  441,067


<FN>

*  2001 excludes amounts in "Assets Pending Sale" in the Consolidated Balance
   Sheet as of December 31, 2001.

The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.

</FN>
</TABLE>


<PAGE>
<TABLE>
<CAPTION>


                                FIRSTENERGY CORP.

                        CONSOLIDATED STATEMENTS OF TAXES

For the Years Ended December 31,                                              2001           2000            1999
---------------------------------------------------------------------------------------------------------------------
                                                                                         (In thousands)
<S>                                                                        <C>            <C>             <C>
GENERAL TAXES:
Real and personal property...........................................      $  176,916     $  281,374      $  276,227
State gross receipts.................................................         102,335        221,385         220,117
Ohio kilowatt-hour excise............................................         117,979             --              --
Social security and unemployment.....................................          44,480         39,134          37,019
Other................................................................          13,630          5,788          10,689
                                                                           ----------     ----------      ----------
       Total general taxes...........................................      $  455,340     $  547,681      $  544,052
                                                                           ==========     ==========      ==========
PROVISION FOR INCOME TAXES:
Currently payable-
   Federal...........................................................      $  375,108     $  467,045      $  433,872
   State.............................................................          84,322         19,918          25,670
   Foreign...........................................................             108             --             --
                                                                           ----------     ----------      ----------
                                                                              459,538        486,963         459,542
                                                                           ----------     ----------      ----------
Deferred, net-
   Federal...........................................................          37,888        (60,831)        (36,021)
   State.............................................................          (6,177)       (18,598)         (9,033)
   Foreign...........................................................             (86)            --              --
                                                                           ----------     ----------      ----------
                                                                               31,625        (79,429)        (45,054)
                                                                           ----------     ----------      ----------
Investment tax credit amortization...................................         (22,545)       (30,732)        (19,661)
                                                                           ----------     ----------      ----------
       Total provision for income taxes..............................      $  468,618     $  376,802      $  394,827
                                                                           ==========     ==========      ==========

RECONCILIATION OF FEDERAL INCOME TAX EXPENSE AT
STATUTORY RATE TO TOTAL PROVISION FOR INCOME TAXES:
Book income before provision for income taxes........................      $1,115,065     $  975,772      $  963,126
                                                                           ==========     ==========      ==========
Federal income tax expense at statutory rate.........................      $  390,273     $  341,520      $  337,094
Increases (reductions) in taxes resulting from-
   Amortization of investment tax credits............................         (22,545)       (30,732)        (19,661)
   State income taxes, net of federal income tax benefit.............          50,794          1,133          10,814
   Amortization of tax regulatory assets.............................          30,419         38,702          23,908
   Amortization of goodwill..........................................          18,416         18,420          19,341
   Preferred stock dividends.........................................          19,733         18,172          22,988
   Other, net........................................................         (18,472)       (10,413)            343
                                                                           ----------     ----------      ----------
       Total provision for income taxes..............................      $  468,618     $  376,802      $  394,827
                                                                           ==========     ==========      ==========

ACCUMULATED DEFERRED INCOME TAXES AT DECEMBER 31:
Property basis differences...........................................      $1,996,937     $1,245,297      $1,878,904
Customer receivables for future income taxes.........................         178,683         62,527         159,577
Competitive transition charge........................................       1,289,438      1,070,161         537,114
Deferred sale and leaseback costs....................................         (77,099)      (128,298)       (129,775)
Nonutility generation costs..........................................        (178,393)            --              --
Unamortized investment tax credits...................................         (86,256)       (85,641)        (96,036)
Unused alternative minimum tax credits...............................              --        (32,215)       (101,185)
Other comprehensive income...........................................        (115,395)            --              --
Other................................................................        (323,696)       (37,724)        (17,334)
                                                                           ----------     ----------      ----------
       Net deferred income tax liability*............................      $2,684,219     $2,094,107      $2,231,265
                                                                           ==========     ==========      ==========
<FN>


*   2001 excludes amounts in "Liabilities Related to Assets Pending Sale" on the
    Consolidated Balance Sheet as of December 31, 2001.

The accompanying Notes to Consolidated Financial Statements are an integral part
of these statements.

</FN>
</TABLE>



<PAGE>



NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.   SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES:

          The consolidated  financial  statements  include  FirstEnergy Corp., a
public utility holding company,  and its principal  electric  utility  operating
subsidiaries,  Ohio Edison  Company (OE),  The Cleveland  Electric  Illuminating
Company  (CEI),  Pennsylvania  Power Company  (Penn),  The Toledo Edison Company
(TE), American  Transmission  Systems, Inc. (ATSI), Jersey Central Power & Light
Company (JCP&L),  Metropolitan Edison Company (Met-Ed) and Pennsylvania Electric
Company  (Penelec).  These  utility  subsidiaries  are referred to throughout as
"Companies." FirstEnergy's 2001 results include the results of JCP&L, Met-Ed and
Penelec for the period November 7, 2001 through  December 31, 2001 (see Note 2 -
Merger).The  consolidated  financial statements also include FirstEnergy's other
principal   subsidiaries:   FirstEnergy   Solutions  Corp.  (FES);   FirstEnergy
Facilities  Services Group, LLC (FEFSG);  MYR Group,  Inc. (MYR);  MARBEL Energy
Corporation  (MARBEL);   FirstEnergy  Nuclear  Operating  Company  (FENOC);  GPU
Capital,  Inc.; GPU Power,  Inc.;  FirstEnergy  Service Company (FECO);  and GPU
Service,  Inc. (GPUS).  FES provides  energy-related  products and services and,
through  its  FirstEnergy   Generation   Corp.   (FGCO)   subsidiary,   operates
FirstEnergy's  nonnuclear  generation  business.  FENOC  operates the Companies'
nuclear generating  facilities.  FEFSG is the parent company of several heating,
ventilating,  air conditioning  and energy  management  companies,  and MYR is a
utility  infrastructure   construction  service  company.   MARBEL  is  a  fully
integrated  natural  gas  company.   GPU  Capital  owns  and  operates  electric
distribution  systems in foreign  countries  (see Note 2 - Merger) and GPU Power
owns and operates  generation  facilities  in foreign  countries.  FECO and GPUS
provide  legal,  financial and other  corporate  support  services to affiliated
FirstEnergy   companies.   Significant   intercompany   transactions  have  been
eliminated in consolidation.

          The Companies follow the accounting policies and practices  prescribed
by the Public  Utilities  Commission  of Ohio (PUCO),  the  Pennsylvania  Public
Utility  Commission (PPUC), the New Jersey Board of Public Utilities (NJBPU) and
the Federal Energy Regulatory  Commission  (FERC).  The preparation of financial
statements in conformity with accounting  principles  generally  accepted in the
United  States  (GAAP)  requires  management  to  make  periodic  estimates  and
assumptions  that affect the reported amounts of assets,  liabilities,  revenues
and expenses and disclosure of contingent assets and liabilities. Actual results
could  differ  from  these  estimates.  Certain  prior  year  amounts  have been
reclassified to conform with the current year presentation.

       REVENUES-

          The Companies'  principal  business is providing  electric  service to
customers in Ohio,  Pennsylvania and New Jersey. The Companies' retail customers
are  metered on a cycle  basis.  Revenue is  recognized  for  unbilled  electric
service provided through the end of the year.

          Receivables  from customers  include sales to residential,  commercial
and industrial customers and sales to wholesale customers. There was no material
concentration  of receivables  as of December 31, 2001 or 2000,  with respect to
any particular segment of FirstEnergy's customers.

          CEI and TE sell substantially all of their retail customer receivables
to  Centerior  Funding  Corp.  (CFC),  a wholly  owned  subsidiary  of CEI.  CFC
subsequently  transfers  the  receivables  to  a  trust  under  an  asset-backed
securitization  agreement.  The trust completed private sales of $50 million and
$150  million  of  receivables-backed  investor  certificates  in 2000 and 2001,
respectively,  in  transactions  that qualified for sale  accounting  treatment.
CFC's  creditors are entitled to be satisfied first out of the proceeds of CFC's
assets.  The 2001  private  sale was  used to repay a 1996  public  sale of $150
million of receivables-backed  investor certificates which was replaced under an
amended securitization agreement. FirstEnergy's retained interest in the pool of
receivables  held by the trust (34% as of December  31,  2001) is stated at fair
value,  reflecting  adjustments  for  anticipated  credit  losses.   Sensitivity
analyses  reflecting  a 10% and 20% increase in the rate of  anticipated  credit
losses did not significantly affect FirstEnergy's  retained interest in the pool
of  receivables.  Of the $301  million sold to the trust and  outstanding  as of
December 31, 2001,  FirstEnergy  had a retained  interest in $101 million of the
receivables.  Accordingly,  receivables  recorded  on the  Consolidated  Balance
Sheets  were  reduced  by  approximately   $200  million  due  to  these  sales.
Collections of receivables  previously transferred to the trust and used for the
purchase of new receivables  from CFC during 2001,  totaled  approximately  $2.2
billion.  CEI and TE processed  receivables for the trust and received servicing
fees of  approximately  $4.5  million  in  2001.  Expenses  associated  with the
factoring discount related to the sale of receivables were $12 million in 2001.

       REGULATORY PLANS-

          Ohio's 1999 electric utility  restructuring  law allowed Ohio electric
customers  to select  their  generation  suppliers  beginning  January  1, 2001,
provided for a five percent  reduction on the generation  portion of residential
customers' bills and the opportunity for utilities to recover  transition costs,
including  regulatory  assets.  Under this law, the PUCO approved  FirstEnergy's
transition plan in 2000 as modified by a settlement agreement with major parties
to the  transition  plan,  which  it  filed on  behalf  of OE,  CEI and TE (Ohio
Companies). The settlement agreement included

<PAGE>

approval for recovery of the amounts of transition costs filed in the transition
plan through no later than 2006 for OE, mid-2007 for TE and 2008 for CEI, except
where a longer period of recovery is provided for in the  settlement  agreement.
The settlement also granted preferred access over FirstEnergy's  subsidiaries to
nonaffiliated  marketers,  brokers and  aggregators  to 1,120  megawatts (MW) of
generation  capacity  through 2005 at  established  prices for sales to the Ohio
Companies'  retail  customers.  The Ohio  Companies'  base  electric  rates  for
distribution service under their prior respective regulatory plans were extended
from December 31, 2005 through  December 31, 2007. The  transition  rate credits
for customers under their prior  regulatory plans were also extended through the
Ohio Companies' respective transition cost recovery periods.

          The  transition  plan  itemized,  or  unbundled,  the current price of
electricity into its component elements -- including  generation,  transmission,
distribution  and  transition   charges.   As  required  by  the  PUCO's  rules,
FirstEnergy's  transition plan also resulted in the corporate  separation of its
regulated and unregulated operations,  operational and technical support changes
needed to accommodate  customer choice, an education program to inform customers
of their  options  under  the law,  and  planned  changes  in how  FirstEnergy's
transmission  system will be operated  to ensure  access to all users.  Customer
prices are frozen through a five-year  market  development  period  (2001-2005),
except for certain limited statutory  exceptions including a 5% reduction in the
price of generation for residential customers.

          FirstEnergy's Ohio customers choosing alternative suppliers receive an
additional  incentive  applied  to the  shopping  credit of 45% for  residential
customers,  30% for commercial customers and 15% for industrial  customers.  The
amount of the incentive  serves to reduce the  amortization of transition  costs
during the market development period and will be recovered through the extension
of the  transition  cost  recovery  periods.  If  the  customer  shopping  goals
established in the agreement are not achieved by the end of 2005, the transition
cost recovery  periods could be shortened for OE, CEI and TE to reduce  recovery
by as much  as $500  million  (OE-$250  million,  CEI-$170  million  and  TE-$80
million),  but any such  adjustment  would be computed on a  class-by-class  and
pro-rata  basis.  Based on annualized  shopping  levels as of December 31, 2001,
FirstEnergy believes the maximum potential recovery reductions are approximately
$174 million (OE - $87 million, CEI - $52 million and TE - $35 million).

          New  Jersey  is  also  evolving  to  a  competitive  electric  utility
marketplace.  In March 2001,  the NJBPU issued a Final Decision and Order (Final
Order) with respect to JCP&L's rate unbundling,  stranded cost and restructuring
filings,  which superseded its 1999 Summary Order. The Final Order confirms rate
reductions set forth in the Summary Order,  which remain in effect at increasing
levels  through July 2003 with rates after July 31, 2003 to be  determined  in a
rate  case  commencing  in 2002.  The Final  Order  also  confirms  the right of
customers to select their  generation  suppliers  effective  August 1, 1999, and
includes the deregulation of electric  generation service costs. The Final Order
confirms the  establishment  of a  non-bypassable  societal  benefits  charge to
recover costs which include nuclear plant  decommissioning  and manufactured gas
plant  remediation,  as well as a non-bypassable  market transition charge (MTC)
primarily to recover stranded costs;  however, the NJBPU deferred making a final
determination of the net proceeds and stranded costs related to prior generating
asset  divestitures  until JCP&L's request for an Internal Revenue Service (IRS)
ruling  regarding  the treatment of  associated  federal  income tax benefits is
acted  upon.  Should the IRS ruling  support  the return of the tax  benefits to
ratepayers,  JCP&L  would  need to  record a  corresponding  charge to income of
approximately $25 million;  there would be no effect to FirstEnergy's net income
as the contingency existed prior to the merger.

          JCP&L has an  obligation to provide basic  generation  service  (BGS),
that is, it must act as provider of last resort (PLR) to non-shopping  customers
as a result of the  NJBPU's  restructuring  plans.  JCP&L  obtains its supply of
electricity to meet its BGS obligation to non-shopping customers almost entirely
from  contracted  and open market  purchases.  JCP&L is  permitted  to defer for
future collection from customers the amounts by which its costs of supplying BGS
to non-shopping  customers and costs incurred under nonutility  generation (NUG)
agreements  exceed amounts  collected  through BGS and MTC rates. As of December
31, 2001,  the  accumulated  deferred cost balance  totaled  approximately  $300
million,  after giving effect to the reduction  discussed below. The Final Order
provided  for the  ability to  securitize  stranded  costs  associated  with the
divested  Oyster Creek  Nuclear  Generation  Station.  In February  2002,  JCP&L
received  NJBPU  authorization  to issue  $320  million of  transition  bonds to
securitize  the  recovery of these  costs.  The NJBPU order also  provides for a
usage-based  non-bypassable  transition  bond charge and for the transfer of the
bondable transition  property to another entity.  JCP&L plans to sell transition
bonds in the second quarter of 2002 which will be recognized on the Consolidated
Balance  Sheet.  The Final Order also allows for  additional  securitization  of
JCP&L's  deferred  balance to the extent  permitted by law upon  application  by
JCP&L and a  determination  by the NJBPU that the  conditions  of the New Jersey
restructuring  legislation  are met. There can be no assurance as to the extent,
if any, that the NJBPU will permit such securitization.

           The obligation to provide BGS to non-shopping customers was bid out
for the period commencing August 1, 2002. In June 2001, the four incumbent New
Jersey electric distribution companies, including JCP&L, filed a joint proposal
seeking NJBPU approval of a competitive bidding process to procure supply for
the provision of BGS for the period of August 1, 2002 through July 31, 2003. In
December 2001, the NJBPU authorized the auctioning of BGS to meet the electric
demands of all customers who have not selected an alternative supplier. BGS for
all four companies, for the period of August 1, 2002 to July 31, 2003, was
simultaneously put out for bid. The auction, which ended on


<PAGE>



February 13, 2002 and was  approved by the NJBPU on February  15, 2002,  removed
JCP&L's  BGS  obligation  of 5,100 MW for the period from August 1, 2002 to July
31, 2003. The auction represents a transitional  mechanism and a different model
for the  procurement  of BGS  commencing  August  1,  2003  may be  adopted.


          On  September  26,  2001,   the  NJBPU  approved  the  merger  between
FirstEnergy  and GPU,  Inc.,  (see  Note 2 -  Merger)  subject  to the terms and
conditions set forth in a Stipulation of Settlement which had been signed by the
major parties in the merger  discussions.  Under this Stipulation of Settlement,
FirstEnergy agreed to reduce JCP&L's regulatory assets by $300 million, in order
to ensure that  customers  receive the benefit of future merger  savings.  JCP&L
wrote  off  $300  million  of its  deferred  costs  upon  receipt  of the  final
regulatory approval for the merger, which occurred on October 29, 2001.

          Pennsylvania enacted its electric utility competition law in 1996 with
the phase-in of customer choice for generation suppliers completed as of January
1, 2001. The PPUC authorized 1998 rate restructuring  plans for Penn, Met-Ed and
Penelec  which  essentially  resulted in the  deregulation  of their  respective
generation businesses.

          In 2000,  the PPUC  disallowed a portion of the  requested  additional
stranded  costs above those amounts  granted in Met-Ed's and Penelec's 1998 rate
restructuring  plan orders.  The PPUC required Met-Ed and Penelec to seek an IRS
ruling  regarding the return of certain  unamortized  investment tax credits and
excess deferred income tax benefits to ratepayers. Similar to JCP&L's situation,
if  the  IRS  ruling  ultimately   supports  returning  these  tax  benefits  to
ratepayers, Met-Ed and Penelec would then reduce stranded costs by approximately
$12  million  and  $25  million,  respectively,   plus  interest  and  record  a
corresponding  charge to income.  Similar to JCP&L,  there would be no effect to
FirstEnergy's net income.

          As a result of their generating asset divestitures, Met-Ed and Penelec
obtain their supply of electricity to meet their PLR obligations almost entirely
from contracted and open market  purchases.  During 2000,  their purchased power
costs  substantially  exceeded the amounts they could recover under their capped
generation rates which are in effect for varying periods, pursuant to their 1998
rate restructuring  plans. In November 2000, Met-Ed and Penelec filed a petition
with the PPUC seeking permission to defer for future recovery their energy costs
in excess of amounts  reflected in their  capped  generation  rates.  In January
2001,  the PPUC  consolidated  this  petition  with the  FirstEnergy/GPU  merger
proceeding (see Note 2 - Merger) for  consideration and resolution in accordance
with the merger procedural schedule.

          In  June  2001,  Met-Ed,   Penelec  and  FirstEnergy  entered  into  a
Settlement  Stipulation with all of the major parties in the combined merger and
rate  relief  proceedings,   that,  in  addition  to  resolving  certain  issues
concerning the PPUC's  approval of the  FirstEnergy/GPU  merger,  also addressed
Met-Ed's and Penelec's  request for PLR rate relief.  On June 20, 2001, the PPUC
entered orders approving the Settlement  Stipulation,  which approved the merger
and  provided  Met-Ed  and  Penelec  PLR rate  relief.  Met-Ed and  Penelec  are
permitted  to defer for future  recovery  the  difference  between  their actual
energy costs and those reflected in their capped generation  rates,  retroactive
to January 1, 2001.  Deferral accounting will continue for such cost differences
through  December 31, 2005;  should energy costs  incurred by Met-Ed and Penelec
during  that period be below  their  respective  capped  generation  rates,  the
difference would be used to reduce their  recoverable  deferred costs.  Met-Ed's
and Penelec's PLR  obligations  have been  extended  through  December 31, 2010.
Met-Ed's and  Penelec's  competitive  transition  charge (CTC)  revenues will be
applied first to PLR costs,  then to non-NUG  stranded  costs and finally to NUG
stranded costs through December 31, 2010.  Met-Ed and Penelec would be permitted
to recover any remaining stranded costs through a continuation of the CTC, after
December 31, 2010, however, such recovery would extend to no later than December
31, 2015. Any amounts not expected to be recovered by December 31, 2015 would be
written off at the time such nonrecovery becomes probable.

          Several parties had filed  Petitions for Review with the  Commonwealth
Court of  Pennsylvania  regarding the PPUC's  orders.  On February 21, 2002, the
Court affirmed the PPUC decision regarding the FirstEnergy/GPU merger, remanding
the decision to the PPUC only with respect to the issue of merger  savings.  The
Court reversed the PPUC's  decision  regarding the PLR obligations of Met-Ed and
Penelec,  and denied the related requests for rate relief by Met-Ed and Penelec.
FirstEnergy is  considering  its response to the Court's  decision,  which could
include  asking  the   Pennsylvania   Supreme  Court  to  review  the  decision.
FirstEnergy is unable to predict the outcome of these matters.

          All of the Companies' regulatory assets are expected to continue to be
recovered  under  provisions  of the Ohio  transition  plan  and the  respective
Pennsylvania  and New Jersey  regulatory  plans.  Under the previous  regulatory
plan,  the PUCO had  authorized  OE to  recognize  additional  capital  recovery
related to its generating assets (which was reflected as additional depreciation
expense) and  additional  amortization  of  regulatory  assets  during the prior
regulatory plan period of at least $2 billion,  and the PPUC had authorized Penn
to accelerate at least $358 million,  more than the amounts that would have been
recognized if the prior  regulatory  plans were not in effect.  These additional
amounts were being recovered  through rates.  Under OE's prior  regulatory plan,
which was  terminated at the end of 2000,  and Penn's rate  restructuring  plan,
OE's and Penn's  cumulative  additional  capital  recovery and regulatory  asset
amortization amounted to $1.424 billion.


<PAGE>

          The application of Statement of Financial  Accounting Standards (SFAS)
No. 71,  "Accounting for the Effects of Certain Types of Regulation"  (SFAS 71),
was discontinued in 1997 with respect to CEI's and TE's nuclear  operations;  in
1998 with respect to Penn's,  Met-Ed's and Penelec's generation  operations;  in
1999 with respect to JCP&L's  generation  operations and in 2000 with respect to
OE's generation business and the nonnuclear generation businesses of CEI and TE.
JCP&L,  Met-Ed and  Penelec  subsequently  divested  substantially  all of their
generating  assets.   The  Securities  and  Exchange   Commission  (SEC)  issued
interpretive  guidance regarding asset impairment  measurement,  concluding that
any supplemental  regulated cash flows such as a CTC should be excluded from the
cash  flows of assets in a portion of the  business  not  subject to  regulatory
accounting practices. If those assets are impaired, a regulatory asset should be
established  if  the  costs  are  recoverable  through  regulatory  cash  flows.
Consistent  with the SEC guidance,  $1.6 billion of impaired  plant  investments
($1.2  billion,  $304 million and $53 million for OE, CEI and TE,  respectively)
were  recognized as regulatory  assets  recoverable as transition  costs through
future  regulatory cash flows.  The following  summarizes net assets included in
property,  plant and equipment  relating to operations for which the application
of SFAS 71 was discontinued, compared with the respective company's total assets
as of December 31, 2001.
                                SFAS 71
                              Discontinued
                                Net Assets       Total Assets
             --------------------------------------------------------
                                       (In millions)
                OE..........     $  984               $7,218
                CEI.........      1,425                5,856
                TE..........        601                2,572
                Penn........         88                  960
                JCP&L.......         46                8,040
                Met-Ed......         18                3,607
             --------------------------------------------------------

       PROPERTY, PLANT AND EQUIPMENT-

          Property,  plant and equipment  reflects original cost (except for the
Ohio  Companies'  and  Penn's  nuclear  generating  units  and  the  former  GPU
companies' properties which were adjusted to fair value),  including payroll and
related  costs such as taxes,  employee  benefits,  administrative  and  general
costs, and interest costs. In addition to FirstEnergy's wholly-owned facilities,
JCP&L holds a 50% ownership  interest in Yards Creek Pumped Storage  Facility --
its net book value was  approximately  $21.5  million as of December  31,  2001.
FirstEnergy also shares ownership  interests in various foreign  properties with
an  aggregate  net book value of $1.9  billion,  representing  the fair value of
FirstEnergy's interest.

          The Companies  provide for  depreciation on a  straight-line  basis at
various rates over the estimated lives of property included in plant in service.
The respective annual composite rates for the Companies' electric plant in 2001,
2000 and 1999 (post merger periods only for JCP&L, Met-Ed and Penelec) are shown
in the following table:

                                      Annual Composite
                                      Depreciation Rate
         ---------------------------------------------------------
                                  2001      2000       1999
                                  ----      ----       ----

           OE...............      2.7%      2.8%       3.0%
           CEI..............      3.2       3.4        3.4
           TE...............      3.5       3.4        3.4
           Penn.............      2.9       2.6        2.5
           JCP&L............      3.4
           Met-Ed...........      3.0
           Penelec..........      2.9
         ---------------------------------------------------------

          Annual  depreciation  expense in 2001  included  approximately  $128.7
million for future  decommissioning costs applicable to the Companies' ownership
and  leasehold  interests  in five nuclear  generating  units,  a  demonstration
nuclear reactor owned by a wholly-owned  subsidiary of JCP&L, Met-Ed and Penelec
and  decommissioning  liabilities for previously divested GPU nuclear generating
units. The 2001 amounts  reflected  increases of approximately  $60 million from
implementing  the Ohio utilities'  transition plan in 2001. The Companies' share
of the future  obligation  to  decommission  these units is  approximately  $2.5
billion in current dollars and (using a 4.0% escalation rate) approximately $5.4
billion in future dollars. The estimated obligation and the escalation rate were
developed based on site specific studies.  Decommissioning  of the demonstration
nuclear   reactor  is  expected  to  be   completed   in  2003;   payments   for
decommissioning  of the nuclear  generating units are expected to begin in 2014,
when  actual  decommissioning  work is  expected to begin.  The  Companies  have
recovered  approximately $568 million for decommissioning through their electric
rates  from  customers  through  December  31,  2001.  The  Companies  have also
recognized an estimated  liability of  approximately  $46.5  million  related to
decontamination and decommissioning of nuclear enrichment facilities operated by
the United States  Department of Energy (DOE),  as required by the Energy Policy
Act of 1992.


<PAGE>


          In July 2001,  the Financial  Accounting  Standards  Board issued SFAS
143,  "Accounting for Asset Retirement  Obligations." The new statement provides
accounting  treatment  for  retirement   obligations  associated  with  tangible
long-lived  assets with adoption  required by January 1, 2003. SFAS 143 requires
the fair value of a liability for an asset retirement  obligation be recorded in
the period in which it is incurred.  The associated  asset  retirement costs are
capitalized as part of the carrying  amount of the long-lived  asset.  Over time
the  capitalized  costs  are  depreciated  and the  present  value of the  asset
retirement liability increases,  resulting in a period expense. Upon retirement,
a gain or loss will be recorded if the costs to settle the retirement obligation
differ from the carrying amount. Under the new standard,  additional assets and
liabilities relating principally to nuclear decommissioning  obligations will be
recorded,  the  pattern of expense  recognition  will change and income from the
external   decommissioning   trusts  will  be  recorded  as  investment  income.
FirstEnergy  is currently  assessing the new standard and has not yet quantified
the impact on its financial statements.

       NUCLEAR FUEL-

          Nuclear fuel is recorded at original cost,  which  includes  material,
enrichment,  fabrication  and interest costs incurred prior to reactor load. The
Companies amortize the cost of nuclear fuel based on the rate of consumption.

       INCOME TAXES-

          Details  of the  total  provision  for  income  taxes are shown on the
Consolidated  Statements  of Taxes.  Deferred  income  taxes  result from timing
differences  in the  recognition of revenues and expenses for tax and accounting
purposes.  Investment tax credits,  which were deferred when utilized, are being
amortized over the recovery period of the related property. The liability method
is used to account for deferred  income taxes.  Deferred  income tax liabilities
related to tax and accounting basis  differences are recognized at the statutory
income tax rates in effect when the liabilities are expected to be paid.

       RETIREMENT BENEFITS-

          FirstEnergy's  trusteed,  noncontributory defined benefit pension plan
covers almost all full-time  employees.  Upon  retirement,  employees  receive a
monthly  pension  based on length of service and  compensation.  On December 31,
2001, the GPU pension plans were merged with the FirstEnergy  plan.  FirstEnergy
uses the projected unit credit method for funding  purposes and was not required
to make pension  contributions  during the three years ended  December 31, 2001.
The assets of the pension plan consist primarily of common stocks, United States
government  bonds and corporate  bonds.  The FirstEnergy and GPU  postretirement
benefit plans are currently separately  maintained;  the information shown below
is  aggregated  as of December  31,  2001.  Costs for the year 2001  include the
former GPU  companies'  pension and other  postretirement  benefit costs for the
period November 7, 2001 through December 31, 2001.

          FirstEnergy   provides  a  minimum  amount  of  noncontributory   life
insurance to retired employees in addition to optional  contributory  insurance.
Health care benefits, which include certain employee deductibles and copayments,
are also available to retired  employees,  their  dependents  and, under certain
circumstances,  their survivors.  FirstEnergy pays insurance premiums to cover a
portion of these benefits in excess of set limits;  all amounts up to the limits
are paid by FirstEnergy.  FirstEnergy  recognizes the expected cost of providing
other  postretirement  benefits to employees and their beneficiaries and covered
dependents  from the time  employees  are hired  until they  become  eligible to
receive those benefits.

          The  following  sets forth the funded  status of the plans and amounts
recognized on the Consolidated Balance Sheets as of December 31:


<PAGE>
<TABLE>
<CAPTION>



                                                                                            Other
                                                            Pension Benefits        Postretirement Benefits
                                                            ----------------        -----------------------
                                                            2001        2000           2001       2000
-----------------------------------------------------------------------------------------------------------
                                                                           (In millions)
              <S>                                         <C>         <C>          <C>           <C>
              Change in benefit obligation:
              Benefit obligation as of January 1......    $1,506.1    $1,394.1     $   752.0     $ 608.4
              Service cost............................        34.9        27.4          18.3        11.3
              Interest cost...........................       133.3       104.8          64.4        45.7
              Plan amendments.........................         3.6        41.3          --          --
              Actuarial loss..........................       123.1        17.3          73.3       121.7
              Voluntary early retirement program......        --          23.4           2.3        --
              GPU acquisition.........................     1,878.3        --           716.9        --
              Benefits paid...........................      (131.4)     (102.2)        (45.6)      (35.1)
              -------------------------------------------------------------------------------------------
              Benefit obligation as of December 31....     3,547.9     1,506.1       1,581.6       752.0
              -------------------------------------------------------------------------------------------

              Change in fair value of plan assets:
              Fair value of plan assets as of January 1    1,706.0     1,807.5          23.0         4.9
              Actual return on plan assets............         8.1         0.7          12.7        (0.2)
              Company contribution....................        --          --            43.3        18.3
              GPU acquisition.........................     1,901.0        --           462.0        --
              Benefits paid...........................      (131.4)     (102.2)         (6.0)       --
              -------------------------------------------------------------------------------------------
              Fair value of plan assets as of December 31  3,483.7     1,706.0         535.0        23.0
              -------------------------------------------------------------------------------------------

              Funded status of plan...................       (64.2)      199.9      (1,046.6)     (729.0)
              Unrecognized actuarial loss (gain)......       222.8       (90.9)        212.8       147.3
              Unrecognized prior service cost.........        87.9        93.1          17.7        20.9
              Unrecognized net transition obligation
               (asset)................................        --          (2.1)       101.6        110.9
              -------------------------------------------------------------------------------------------
              Prepaid (accrued) benefit cost..........    $  246.5    $  200.0     $  (714.5)    $(449.9)
              ===========================================================================================

              Assumptions used as of December 31:
              Discount rate...........................        7.25%       7.75%         7.25%       7.75%
              Expected long-term return on plan assets       10.25%      10.25%        10.25%      10.25%
              Rate of compensation increase...........        4.00%       4.00%         4.00%       4.00%
              ===========================================================================================
</TABLE>



           Net pension and other postretirement benefit costs for the three
years ended December 31, 2001 were computed as follows:

<TABLE>
<CAPTION>

                                                                                            Other
                                                       Pension Benefits             Postretirement Benefits
                                                 ------------------------         -------------------------
                                                 2001      2000      1999         2001      2000     1999
     ------------------------------------------------------------------------------------------------------
                                                                       (In millions)

    <S>                                        <C>       <C>      <C>             <C>       <C>      <C>
     Service cost............................  $  34.9   $  27.4  $  28.3         $18.3     $11.3    $ 9.3
     Interest cost...........................    133.3     104.8    102.0          64.4      45.7     40.7
     Expected return on plan assets..........   (204.8)   (181.0)  (168.1)         (9.9)     (0.5)    (0.4)
     Amortization of transition obligation
      (asset)................................     (2.1)     (7.9)    (7.9)          9.2       9.2      9.2
     Amortization of prior service cost......      8.8       5.7      5.7           3.2       3.2      3.3
     Recognized net actuarial loss (gain)....     --        (9.1)    --             4.9      --       --
     Voluntary early retirement program......      6.1      17.2     --             2.3      --       --
     ------------------------------------------------------------------------------------------------------
     Net benefit cost........................  $ (23.8)  $ (42.9) $ (40.0)        $92.4     $68.9    $62.1
     ======================================================================================================

</TABLE>


          The composite health care trend rate assumption is  approximately  10%
in 2002,  9% in 2003 and 8% in 2004,  trending to 4%-6% in later years.  Assumed
health care cost trend rates have a significant  effect on the amounts  reported
for the health care plan.  An increase in the health care trend rate  assumption
by one  percentage  point would  increase the total  service and  interest  cost
components by $14.6 million and the postretirement  benefit obligation by $151.2
million.  A  decrease  in the same  assumption  by one  percentage  point  would
decrease the total service and interest cost components by $12.7 million and the
postretirement benefit obligation by $131.3 million.

       SUPPLEMENTAL CASH FLOWS INFORMATION-

          All temporary cash  investments  purchased with an initial maturity of
three  months  or less are  reported  as cash  equivalents  on the  Consolidated
Balance  Sheets at cost,  which  approximates  their fair market value.  Noncash
financing and investing  activities  included the 2001 FirstEnergy  common stock
issuance of $2.6 billion for the GPU acquisition and capital lease  transactions
amounting to $3.1  million,  $89.3 million and $36.2 million for the years 2001,
2000  and  1999,  respectively.  Commercial  paper  transactions  of  OES  Fuel,
Incorporated  (a  wholly  owned  subsidiary  of OE) that have  initial  maturity
periods of three  months or less are reported  net within  financing  activities
under  long-term debt and are reflected as currently  payable  long-term debt on
the Consolidated Balance Sheets in anticipation of the expiration of the related
long-term financing agreement in March 2002 (see Note 4G).


<PAGE>


          All  borrowings  with  initial  maturities  of less  than one year are
defined as financial instruments under GAAP and are reported on the Consolidated
Balance  Sheets  at cost,  which  approximates  their  fair  market  value.  The
following sets forth the approximate  fair value and related carrying amounts of
all other  long-term debt,  preferred stock subject to mandatory  redemption and
investments other than cash and cash equivalents as of December 31:


                                                2001                2000
-------------------------------------------------------------------------------
                                        Carrying      Fair   Carrying     Fair
                                         Value       Value    Value      Value
--------------------------------------------------------------------------------
                                                     (In millions)
 Long-term debt*...................     $12,897     $13,097   $5,853     $6,010
 Preferred stock...................     $   636     $   626   $  247     $  243
 Investments other than cash
   and cash equivalents:
     Debt securities:
        Maturity (5-10 years)......     $   439     $   402   $  460     $  441
        Maturity (more than 10 years)       990       1,009    1,026      1,051
     Equity securities.............          15          15       16         16
     All other.....................       1,730       1,734      924        935
--------------------------------------------------------------------------------
                                        $ 3,174     $ 3,160   $2,426     $2,443
================================================================================

 * Excluding approximately $1.75 billion of long-term in 2001 debt related to
   pending divestitures.

          The fair values of  long-term  debt and  preferred  stock  reflect the
present value of the cash  outflows  relating to those  securities  based on the
current  call  price,  the yield to  maturity  or the  yield to call,  as deemed
appropriate at the end of each respective year. The yields assumed were based on
securities  with similar  characteristics  offered by  corporations  with credit
ratings  similar to the Companies'  ratings.  Long-term debt and preferred stock
subject to mandatory  redemption of the former GPU companies were  recognized at
fair value in connection with the merger.

          The fair value of  investments  other  than cash and cash  equivalents
represent cost (which  approximates fair value) or the present value of the cash
inflows  based on the  yield to  maturity.  The  yields  assumed  were  based on
financial instruments with similar characteristics and terms.  Investments other
than  cash and  cash  equivalents  include  decommissioning  trust  investments.
Unrealized gains and losses applicable to the  decommissioning  trusts have been
recognized  in  the  trust  investment  with  a  corresponding   change  to  the
decommissioning  liability.  The Companies  have no securities  held for trading
purposes.

          Effective  December 31, 1998,  FirstEnergy  began  accounting  for its
commodity price derivatives,  entered into specifically for trading purposes, on
a  mark-to-market  basis in accordance  with  Emerging  Issues Task Force (EITF)
Issue No. 98-10, "Accounting for Energy Trading and Risk Management Activities,"
with gains and losses recognized in the Consolidated Statements of Income.

          On January 1, 2001,  FirstEnergy  adopted  SFAS 133,  "Accounting  for
Derivative  Instruments  and  Hedging  Activities",  as  amended  by  SFAS  138,
"Accounting for Certain Derivative Instruments and Certain Hedging Activities --
an amendment of FASB  Statement No. 133".  The  cumulative  effect to January 1,
2001 was a charge of $8.5 million (net of $5.8 million of income  taxes) or $.03
per share of common  stock.  The reported  results of  operations  for the years
ended  December  31, 2000 and 1999 would not have been  materially  different if
this accounting had been in effect during those years.

          FirstEnergy  is  exposed  to  financial   risks   resulting  from  the
fluctuation  of interest  rates and  commodity  prices,  including  electricity,
natural gas and coal.  To manage the  volatility  relating  to these  exposures,
FirstEnergy  uses  a  variety  of  non-derivative  and  derivative  instruments,
including  forward  contracts,   options,   futures  contracts  and  swaps.  The
derivatives are used  principally for hedging  purposes and, to a lesser extent,
for  trading  purposes.   FirstEnergy's  Risk  Policy  Committee,  comprised  of
executive  officers,  exercises an independent risk oversight function to ensure
compliance with corporate risk  management  policies and prudent risk management
practices.

          FirstEnergy uses derivatives to hedge the risk of price, interest rate
and  foreign  currency  fluctuations.   FirstEnergy's  primary  ongoing  hedging
activity involves cash flow hedges of electricity and natural gas purchases. The
maximum  periods over which the  variability of electricity and natural gas cash
flows are hedged are two and three  years,  respectively.  Gains and losses from
hedges of commodity  price risks are included in net income when the  underlying
hedged  commodities  are  delivered.  FirstEnergy  entered  into  interest  rate
derivative  transactions  during  2001 to  hedge a  portion  of the  anticipated
interest payments on debt related to the GPU acquisition.  Gains and losses from
hedges of anticipated  interest payments on acquisition debt will be included in
net income over the periods that hedged  interest  payments are made - 5, 10 and
30  years.  The  current  net  deferred  loss  of  $169.4  million  included  in
Accumulated  Other  Comprehensive  Loss  (AOCL) as of  December  31,  2001,  for
derivative  hedging  activity,  as compared to the  December 31, 2000 balance of
$44.2 million (including the SFAS 133 cumulative  adjustment) in deferred gains,
resulted from a $181.1 million reduction related to current hedging activity and
a $32.5 million reduction due to net hedge gains included in earnings during the
year.  Approximately  $40.7 million (after tax) of the current net deferred loss
on
<PAGE>


derivative instruments in AOCL is expected to be reclassified to earnings during
the next twelve months as hedged transactions occur.  However, the fair value of
these  derivative  instruments  will  fluctuate  from period to period  based on
various  market  factors and will generally be more than offset by the margin on
related sales and revenues.

       REGULATORY ASSETS-

          The Companies  recognize,  as regulatory assets, costs which the FERC,
PUCO,  PPUC and NJBPU have  authorized  for  recovery  from  customers in future
periods. Without such authorization, the costs would have been charged to income
as incurred. All regulatory assets are expected to continue to be recovered from
customers under the Companies' respective transition and regulatory plans. Based
on those plans, the Companies  continue to bill and collect cost-based rates for
their   transmission  and  distribution   services,   which  remain   regulated;
accordingly,  it is appropriate  that the Companies  continue the application of
SFAS 71 to those operations.  OE and Penn recognized additional cost recovery of
$270 million in 2000 and $257 million in 1999,  as additional  regulatory  asset
amortization  in  accordance  with  their  prior Ohio and  current  Pennsylvania
regulatory plans. The Ohio companies and Penn recognized  incremental transition
cost  recovery  aggregating  $309  million in  accordance  with the current Ohio
transition plan and Pennsylvania regulatory plan.

          Net regulatory assets on the Consolidated Balance Sheets are comprised
of the following:

                                                       2001       2000
   -----------------------------------------------------------------------
                                                        (In millions)

   Regulatory transition charge...................   $7,751.5    $3,489.0
   Customer receivables for future income taxes...      433.0       139.9
   Societal benefits charge.......................      166.6        --
   Loss on reacquired debt........................       80.0        51.0
   Employee postretirement benefit costs..........       98.6        15.3
   Nuclear decommissioning, decontamination and
     spent fuel disposal costs....................       80.2        --
   Provider of last resort costs..................      116.2        --
   Property losses and unrecovered plant costs....      104.1        --
   Other..........................................       82.4        32.5
   ----------------------------------------------------------------------
         Total                                       $8,912.6    $3,727.7
   ======================================================================

2.   MERGER:

          On  November  7,  2001,  the  merger  of  FirstEnergy  and GPU  became
effective  pursuant to the  Agreement  and Plan of Merger,  dated August 8, 2000
(Merger  Agreement).  As a result  of the  merger,  GPU's  former  wholly  owned
subsidiaries,  including JCP&L, Met-Ed and Penelec (collectively, the Former GPU
Companies), became wholly owned subsidiaries of FirstEnergy.

          Under the terms of the Merger Agreement, GPU shareholders received the
equivalent  of $36.50 for each share of GPU common stock they owned,  payable in
cash and/or  FirstEnergy  common stock. GPU shareholders  receiving  FirstEnergy
shares received 1.2318 shares of FirstEnergy  common stock for each share of GPU
common stock that they exchanged. The elections by GPU shareholders were subject
to proration since the total elections received would have resulted in more than
one-half  of the GPU  common  stock  being  exchanged  for  FirstEnergy  shares.
FirstEnergy borrowed the funds for the cash portion of the merger consideration,
approximately  $2.2 billion,  through a credit  agreement dated as of October 2,
2001, from a group of banks led by Barclay's Bank Plc, as administrative  agent;
the  borrowings  were  refinanced  with  long-term  debt on November  15,  2001.
FirstEnergy  issued  nearly  73.7  million  shares  of its  common  stock to GPU
shareholders for the share portion of the transaction consideration.

          The merger was accounted for by the purchase method of accounting and,
accordingly,  the  Consolidated  Statements of Income include the results of the
Former GPU  Companies  beginning  November  7, 2001.  The  assets  acquired  and
liabilities  assumed were  recorded at estimated  fair values as  determined  by
FirstEnergy's management based on information currently available and on current
assumptions as to future operations. The merger purchase accounting adjustments,
which were  recorded  in the  records of GPU's  direct  subsidiaries,  primarily
consist of: (1) revaluation of GPU's international operations to fair value; (2)
revaluation of property,  plant and  equipment;  (3) adjusting  preferred  stock
subject to mandatory  redemption and long-term debt to estimated fair value; (4)
recognizing  additional  obligations  related to  retirement  benefits;  and (5)
recognizing estimated severance and other compensation liabilities. Other assets
and  liabilities  were not adjusted since they remain subject to rate regulation
on a historical cost basis. The severance and compensation liabilities are based
on anticipated  workforce  reductions  reflecting  duplicate positions primarily
related to corporate support groups including  finance,  legal,  communications,
human resources and information  technology.  The workforce reductions represent
the  expected   reduction  of  approximately   1,000  employees  at  a  cost  of
approximately  $140 million.  Merger related  staffing  reductions began in late
2001 and the  remaining  reductions  are  anticipated  to occur  through 2003 as
merger-related transition assignments are completed.

<PAGE>


          The  merger  greatly  expanded  the  size and  scope  of our  electric
business and the goodwill recognized primarily relates to the regulated services
segment.

          The following table summarizes the estimated fair values of the assets
acquired and liabilities  assumed at the date of acquisition.  The allocation of
the purchase price is subject to adjustment within one year of the merger.

                                                (In millions)
      -----------------------------------------------------------
      Current assets...................    $ 1,027
      Goodwill.........................      3,698
      Regulatory assets................      4,352
      Other............................      5,595
                                           -------
          Total assets acquired........                 14,672

      Current liabilities..............     (2,615)
      Long-term debt...................     (2,992)
      Other............................     (4,785)
                                          --------
          Total liabilities assumed....                (10,392)
      Net assets acquired pending sale.                    566
                                                      --------

      Net assets acquired..............               $  4,846


       DIVESTITURES-INTERNATIONAL OPERATIONS

          Prior  to  consummation  of the  GPU  merger,  FirstEnergy  identified
certain GPU international  operations (see below) for divestiture  within twelve
months of the merger date.  These  operations  constitute  individual  "lines of
business"  as defined  in  Accounting  Principles  Board  Opinion  (APB) No. 30,
"Reporting  the Results of  Operations - Reporting  the Effects of Disposal of a
Segment of a Business,  and  Extraordinary,  Unusual and Infrequently  Occurring
Events and Transactions" with physically and operationally separable activities.
Application of EITF Issue No. 87-11,  "Allocation of Purchase Price to Assets to
Be Sold,"  required that expected,  pre-sale cash flows,  including  incremental
interest costs on related  acquisition  debt, of these  operations be considered
part of the purchase  price  allocation.  Accordingly,  subsequent to the merger
date,  results of operations  and  incremental  interest  costs related to these
international  subsidiaries have not been included in FirstEnergy's Consolidated
Statement   of  Income.   Additionally,   assets  and   liabilities   of  these
international  operations  have been segregated  under separate  captions on the
Consolidated Balance Sheet as "Assets Pending Sale" and "Liabilities Related to
Assets Pending Sale" (see the tables below). The following entities are included
in such captions:

Australia - Gas Transmission (GasNet)
-------------------------------------
GasNet Pty Ltd. and subsidiaries
GPU GasNet Trading Pty Ltd. (and related trusts)

United Kingdom - Electric Distribution
--------------------------------------
Avon Energy Partners Holdings
Avon Energy Partners plc
Midlands Electricity plc
Midlands Power International Ltd.

Argentina - Electric Distribution
---------------------------------
GPU Empresa Distribuidora Electrica Regional S.A. and affiliates

          In December 2001, FirstEnergy divested its Australian gas transmission
companies  through an initial public offering of GasNet's common stock.  The IPO
provided net proceeds of $125 million to  FirstEnergy  and  immediately  removed
$290 million of GasNet-related debt from FirstEnergy's consolidated debt.

          On October 18, 2001,  FirstEnergy and Aquila, Inc. (formerly UtiliCorp
United)  announced  that Aquila made an offer to  FirstEnergy  to purchase  Avon
Energy Partners Holdings, FirstEnergy's wholly owned holding company of Midlands
Electricity  plc, for $2.1 billion  including the  assumption of $1.7 billion of
debt.  FirstEnergy accepted the offer upon completion of its merger with GPU and
regulatory  approvals  for the  transaction  have been  received by Aquila.  One
condition  of  regulatory  approval  requires  that  Aquila  include a financial
partner in the transaction. The transaction must be completed by April 26, 2002,
or  either  party may  terminate  the  original  agreement.  On March 18,  2002,
FirstEnergy  announced that it finalized  terms of the agreement in which Aquila
will  acquire a 79.9  percent  interest in Avon for  approximately  $1.9 billion
(including the transfer of $1.7 billion of debt).

          FirstEnergy and Aquila together will own all of the outstanding shares
of Avon  through  a  jointly  owned  subsidiary,  with  each  company  having  a
50-percent voting interest.


<PAGE>

          Midlands  maintains a defined benefit pension plan covering almost all
full-time  employees of Midlands.  The plan is  maintained  separately  from the
FirstEnergy  plan and will  transfer upon  completion  of the sale.  The pension
benefit obligations as of the November 7, 2001 merger date and December 31, 2001
were approximately $1,263 million and $1,264 million, respectively, with the net
change  primarily due to actuarial  gains of $12 million offset by benefits paid
of $11  million.  The fair  values  of plan  assets as of  November  7, 2001 and
December  31,  2001,  were  approximately  $1,313  million  and $1,291  million,
respectively,  with the change  including  benefits  paid of  approximately  $11
million.  The 2001  post-merger  net periodic  benefit income for the last seven
weeks of 2001 was approximately $3 million.  The plan assumptions as of December
31, 2001 included a discount rate of 6.0%, an expected  return on plan assets of
7.0% and a rate of compensation increase of 4.5%.

          As with the other international  subsidiaries  identified above, GPU's
former  Argentina  operations,  including  GPU Empresa  Distribuidora  Electrica
Regional S.A.,  were  identified by FirstEnergy  for  divestiture  within twelve
months of the merger date.  FirstEnergy  is actively  pursuing the sale of these
operations.   FirstEnergy  has  determined  the  fair  value  of  the  Argentina
operations based on the best available information as of the date of the merger.
Subsequent to that date, a number of economic  events have occurred in Argentina
which may have an impact on FirstEnergy's  ability to realize the estimated fair
value of the Argentina  operations.  These events include currency  devaluation,
restrictions on repatriation of cash, and the anticipation of future asset sales
in that  region by  competitors.  FirstEnergy  has  determined  that the current
economic  conditions  in Argentina  have not eroded the fair value  recorded for
these operations, and as a result, an impairment writedown of this investment is
not warranted as of December 31, 2001.  FirstEnergy  will continue to assess the
potential  impact of these and other related events on the  realizability of the
value recorded for the Argentina operations.  Other international  companies are
being considered for sale,  however;  as of the merger date those sales were not
judged to be probable of occurring within twelve months.

          Post-merger  results of operations and incremental  interest costs for
the international  operations included in "Assets Pending Sale" and "Liabilities
Related to Assets Pending Sale" on FirstEnergy's  Consolidated  Balance Sheet as
of December 31, 2001, are as follows:

Post-Merger Deferred Results of Operations and Interest Costs

                                             International Operations
                                  -------------------------------------------
                                               United
                                  Australia*  Kingdom     Argentina     Total
                                  ----------  -------     ---------     -----
                                                 (In millions)
Revenues.........................    $4.0      $ 99.4      $ 28.5     $131.9
Expenses.........................     2.9        58.3        62.8      124.0
Capitalized incremental interest
  costs..........................     0.5         3.2         1.3        5.0
Net interest charges.............     1.2        20.2         3.2       24.6
Income taxes.....................     0.2       (20.5)      (13.1)     (33.4)
                                  --------------------------------------------
   Net income (loss) capitalized.    $0.2      $ 44.6      $(23.1)    $ 21.7
                                  ============================================

*  Australian operations divested in December 2001


Consolidated Balance Sheets as of December 31, 2001

                                                 International Operations
                                          ----------------------------------
                                           United
                                          Kingdom      Argentina       Total
                                          -------      ---------       -----
Assets Pending Sale
                                                      (In millions)
Current assets........................   $  554          $ 41        $  595
Property, plant and equipment.........    1,738           177         1,915
Investments...........................      142            --           142
Deferred charges......................      691            75           766
                                         -----------------------------------
   Total..............................   $3,125          $293        $3,418
                                         ===================================


Liabilities Related to Assets Pending Sale

Current liabilities:
   Currently payable long-term debt...   $  316          $  2        $  318
   Short-term debt....................      207            27           234
   Other..............................      501             2           503
Long-term debt........................    1,347            85         1,432
Deferred credits*......................     455            13           468
                                         ------------------------------------
   Total..............................   $2,826          $129        $2,955
                                         ====================================

Net Assets Pending Sale...............   $  299          $164        $  463
                                         ====================================

* United Kingdom and Argentina are net of $3 million and $52 million,
  respectively, related to currency translation adjustments.

<PAGE>

       SALE OF GENERATING ASSETS-

          On November  29, 2001,  FirstEnergy  reached an agreement to sell four
coal-fired  power plants (with an aggregate net book value of $539 million as of
December 31, 2001) totaling 2,535 MW to NRG Energy,  Inc. (NRG) for $1.5 billion
($1.355 billion in cash and $145 million in debt assumption). The net, after-tax
gain from the sale, based on the difference between the sale price of the plants
and their market price used in our Ohio  restructuring  transition plan, will be
credited  to  customers  by  reducing  the  transition  cost  recovery   period.
FirstEnergy  also entered into a power purchase  agreement (PPA) with NRG. Under
the terms of the PPA, NRG is obligated to sell to FirstEnergy up to 10.5 billion
kilowatt-hours of electricity annually,  similar to the average annual output of
the plants, through 2005. The sale is expected to close in mid-2002.

3.   LEASES:

          The Companies lease certain  generating  facilities,  office space and
other property and equipment under cancelable and noncancelable leases.

          OE sold portions of its ownership interests in Perry Unit 1 and Beaver
Valley Unit 2 and entered into  operating  leases on the portions sold for basic
lease terms of  approximately  29 years.  CEI and TE also sold portions of their
ownership interests in Beaver Valley Unit 2 and Bruce Mansfield Units 1, 2 and 3
and entered into similar  operating  leases for lease terms of  approximately 30
years.  During the terms of their respective  leases, OE, CEI and TE continue to
be  responsible,  to the  extent  of their  individual  combined  ownership  and
leasehold interests,  for costs associated with the units including construction
expenditures,  operation  and  maintenance  expenses,  insurance,  nuclear fuel,
property taxes and  decommissioning.  They have the right,  at the expiration of
the respective  basic lease terms, to renew their respective  leases.  They also
have the right to purchase the  facilities at the  expiration of the basic lease
term or renewal  term (if  elected) at a price equal to the fair market value of
the facilities.  The basic rental payments are adjusted when applicable  federal
tax law changes.

          OES Finance,  Incorporated, a wholly owned subsidiary of OE, maintains
deposits pledged as collateral to secure  reimbursement  obligations relating to
certain  letters of credit  supporting  OE's  obligations  to lessors  under the
Beaver Valley Unit 2 sale and leaseback  arrangements.  The deposits  pledged to
the  financial  institution  providing  those  letters  of  credit  are the sole
property of OES Finance. In the event of liquidation, OES Finance, as a separate
corporate entity,  would have to satisfy its obligations to creditors before any
of its assets could be made  available to OE as sole owner of OES Finance common
stock.

          Consistent with the regulatory treatment,  the rentals for capital and
operating  leases  are  charged  to  operating   expenses  on  the  Consolidated
Statements  of Income.  Such costs for the three years ended  December 31, 2001,
are summarized as follows:

                                       2001          2000         1999
   --------------------------------------------------------------------
                                                 (In millions)
    Operating leases
      Interest element............     $194.1       $202.4       $208.6
      Other.......................      120.5        111.1        110.3
    Capital leases
      Interest element............        8.0         12.3         17.5
      Other.......................       35.5         64.2         76.1
    -------------------------------------------------------------------
         Total rentals............     $358.1       $390.0       $412.5
    ===================================================================

           The future minimum lease payments as of December 31, 2001, are:

                                                     Operating Leases
                                            -----------------------------------
                                Capital       Lease      Capital
                                Leases      Payments      Trusts          Net
--------------------------------------------------------------------------------
                                                       (In millions)
 2002..........................   $ 6.1     $  322.2     $  169.5      $  152.7
 2003..........................     6.2        332.9        176.5         156.4
 2004..........................     6.0        294.9        110.7         184.2
 2005..........................     5.4        314.6        128.8         185.8
 2006..........................     5.4        323.2        140.2         183.0
 Years thereafter..............     9.8      3,131.8      1,095.4       2,036.4
 ------------------------------------------------------------------------------
 Total minimum lease payments..    38.9     $4,719.6     $1,821.1      $2,898.5
                                            ========     ========      ========
 Executory costs...............     8.8
 --------------------------------------
 Net minimum lease payments....    30.1
 Interest portion..............    10.7
 --------------------------------------
 Present value of net minimum
   lease payments..............    19.4
 Less current portion..........     2.0
 --------------------------------------
 Noncurrent portion............   $17.4
 ======================================

<PAGE>

          OE  invested  in the PNBV  Capital  Trust,  which was  established  to
purchase a portion of the lease  obligation bonds issued on behalf of lessors in
OE's Perry Unit 1 and Beaver Valley Unit 2 sale and leaseback transactions.  CEI
and TE  established  the  Shippingport  Capital  Trust  to  purchase  the  lease
obligation bonds issued on behalf of lessors in their Bruce Mansfield Units 1, 2
and 3 sale and leaseback  transactions.  The PNBV and Shippingport capital trust
arrangements effectively reduce lease costs related to those transactions.

4.   CAPITALIZATION:

     (A) RETAINED EARNINGS-

          There are no  restrictions  on retained  earnings  for payment of cash
dividends on FirstEnergy's common stock.

     (B) EMPLOYEE STOCK OWNERSHIP PLAN-

          FirstEnergy  funds the matching  contribution  for its 401(k)  savings
plan through an ESOP Trust. All full-time  employees  eligible for participation
in the 401(k)  savings  plan are  covered by the ESOP.  The ESOP  borrowed  $200
million   from  OE  and  acquired   10,654,114   shares  of  OE's  common  stock
(subsequently  converted to FirstEnergy  common stock) through market purchases.
Dividends on ESOP shares are used to service the debt.  Shares are released from
the ESOP on a pro rata basis as debt service  payments are made.  In 2001,  2000
and 1999, 834,657 shares, 826,873 shares and 627,427 shares, respectively,  were
allocated to employees with the  corresponding  expense  recognized based on the
shares allocated  method.  The fair value of 5,117,375 shares  unallocated as of
December  31,  2001,  was  approximately  $179.0  million.   Total  ESOP-related
compensation expense was calculated as follows:

                                                   2001      2000        1999
-----------------------------------------------------------------------------
                                                        (In millions)
 Base compensation...........................      $25.1     $18.7      $18.3
 Dividends on common stock held by the ESOP
   and used to service debt..................       (6.1)     (6.4)      (4.5)
-----------------------------------------------------------------------------
     Net expense.............................      $19.0     $12.3      $13.8
=============================================================================


     (C) STOCK COMPENSATION PLANS-

          In 2001,  FirstEnergy  assumed  responsibility for two new stock-based
plans as a result of the merger  with GPU. No further  stock based  compensation
can be awarded under the GPU, Inc.  Stock Option and  Restricted  Stock Plan for
MYR Group Inc. Employees (MYR Plan) or the 1990 Stock Plan for Employees of GPU,
Inc. and  Subsidiaries  (GPU Plan).  All options and restricted stock under both
Plans have been converted into FirstEnergy options and restricted stock. Options
under the GPU Plan became fully  vested on November 7, 2001,  and will expire on
or before June 1, 2010.  Under the MYR Plan,  all options and  restricted  stock
maintained their original vesting periods,  which range from one to four years,
and will expire on or before December 17, 2006.

          Additional stock based plans  administered by FirstEnergy  include the
Centerior  Equity  Plan (CE Plan) and the  FirstEnergy  Executive  and  Director
Incentive Compensation Plan (FE Plan). All options are fully vested under the CE
Plan, and no further awards are permitted. Outstanding options will expire on or
before  February 25, 2007.  Under the FE Plan,  total  awards  cannot  exceed 15
million  shares of common  stock or their  equivalent.  Only stock  options  and
restricted stock have been granted, with vesting periods ranging from six months
to seven years.

          Collectively,  the above  plans are  referred  to as the FE  Programs.
Restricted common stock grants under the FE Programs were as follows:

                                              2001        2000         1999
---------------------------------------------------------------------------

    Restricted common shares granted.....   133,162     208,400       8,000
    Weighted average market price .......    $35.68      $26.63      $30.89
    Weighted average vesting period (years)     3.7         3.8         5.8
    Dividends restricted.................       *           Yes         Yes
    -----------------------------------------------------------------------

     *  FE Plan dividends are paid as restricted stock on 4,500
        shares; MYR Plan dividends are paid as unrestricted cash
        on 128,662 shares


<PAGE>


           Stock option activity under the FE Programs was as follows:

                                            Number of      Weighted Average
       Stock Option Activity                 Options        Exercise Price
-----------------------------------------------------------------------------
  Balance, December 31, 1998............      364,286            $27.13
  (182,330 options exercisable).........                          24.44

    Options granted.....................    1,811,658             24.90
    Options exercised...................       22,575             21.42
  Balance, December 31, 1999............    2,153,369             25.32
  (159,755 options exercisable).........                          24.87

    Options granted.....................    3,011,584             23.24
    Options exercised...................       90,491             26.00
    Options forfeited...................       52,600             22.20
  Balance,  December 31, 2000...........    5,021,862             24.09
  (473,314 options exercisable).........                          24.11

    Options granted.....................    4,240,273             28.11
    Options exercised...................      694,403             24.24
    Options forfeited...................      120,044             28.07
  Balance, December 31, 2001............    8,447,688             26.04
  (1,828,341 options exercisable).......                          24.83
  ---------------------------------------------------------------------

          As of December 31, 2001, the weighted  average  remaining  contractual
life of outstanding stock options was 7.8 years.

          Under the Executive Deferred  Compensation Plan, covered employees can
direct a portion of their  Annual  Incentive  Award  and/or Long Term  Incentive
Award into an unfunded  FirstEnergy Stock Account to receive vested stock units.
An  additional  20%  premium is received in the form of stock units based on the
amount  allocated to the  FirstEnergy  Stock  Account.  Dividends are calculated
quarterly  on stock  units  outstanding  and are paid in the form of  additional
stock units. Upon withdrawal,  stock units are converted to FirstEnergy  shares.
Payout  occurs three years from the date of  deferral.  As of December 31, 2001,
there were 234,558 stock units outstanding.

          FirstEnergy continues to apply APB 25, "Accounting for Stock Issued to
Employees." As required by SFAS 123, "Accounting for Stock-Based  Compensation,"
FirstEnergy  has  determined  pro  forma  earnings  as  though  FirstEnergy  had
accounted for employee  stock options under the fair value method.  The weighted
average  assumptions used in valuing the options and their resulting fair values
are as follows:

                                     2001           2000            1999
----------------------------------------------------------------------------
 Valuation assumptions:
   Expected option term (years)       8.3            7.6             6.4
   Expected volatility.........     23.45%         21.77%          20.03%
   Expected dividend yield.....      5.00%          6.68%           5.97%
   Risk-free interest rate.....      4.67%          5.28%           5.97%
 Fair value per option.........     $4.97          $2.86           $3.42
 ---------------------------------------------------------------------------

          The following  table  summarizes the pro forma effect of applying fair
value accounting to FirstEnergy's stock options.

                                        2001           2000          1999
-----------------------------------------------------------------------------
    Net Income (000)
      As Reported.................   $646,447        $598,970      $568,299
      Pro Forma...................   $642,724        $597,378      $567,876
--------------------------------------------------------------------------------
    Earnings Per Share
      of Common Stock -
    Basic
      As Reported.................      $2.82           $2.69         $2.50
      Pro Forma...................      $2.80           $2.69         $2.50
    Diluted*
      As Reported.................      $2.81           $2.69         $2.50
      Pro Forma...................      $2.79           $2.69         $2.50

   * The denominator used in the calculation of diluted earnings per
     share of common stock includes the weighted average number of
     common shares outstanding (used as the denominator for the
     calculation of basic earnings per share of common stock) plus
     common stock equivalents resulting from the stock-based
     compensation plans discussed above-including 723,931 for options
     and 194,107 for stock units.


<PAGE>


     (D) PREFERRED AND PREFERENCE STOCK-

          JCP&L's  7.52% Series K of  preferred  stock has a  restriction  which
prevents  early  redemption  prior  to June  2002.  Penn's  7.75%  series  has a
restriction  which prevents early  redemption  prior to July 2003.  CEI's $90.00
Series S has no optional redemption provision.  All other preferred stock may be
redeemed by the Companies in whole, or in part, with 30-90 days' notice.

          TE  exercised  its  option to redeem  all  outstanding  shares of five
series of preferred stock on February 1, 2002 as follows:

      Series            Outstanding Shares        Call Price
      ------------------------------------------------------
      $  7.76                  150,000              $102.44
      $  7.80                  150,000              $101.65
      $  8.32                  100,000              $102.46
      $ 10.00                  190,000              $101.00
      $  2.21                1,000,000              $ 25.25
      -----------------------------------------------------

          CEI redeemed, pursuant to redemption provisions of its $42.40 Series T
issue, all 200,000 shares outstanding on February 1, 2002 at a price of $500 per
share.

          Met-Ed's and Penelec's  preferred stock  authorization  consists of 10
million and 11.435 million shares, respectively, without par value. No preferred
shares are currently outstanding for the two companies.

          The Companies'  preference stock  authorization  consists of 8 million
shares without par value for OE; 3 million shares without par value for CEI; and
5 million  shares,  $25 par value for TE. No  preference  shares  are  currently
outstanding.

     (E) PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION-

           Annual sinking fund provisions for the Companies' preferred stock are
as follows:

                                                             Redemption
                                                              Price Per
                     Series                Shares              Share
---------------------------------------------------------------------------
CEI                  $ 7.35  C              10,000             $  100
                      90.00  S              17,750              1,000
JCP&L                  8.65% J              83,333                100
                       7.52% K              25,000                100
Penn                  7.625%                 7,500                100
---------------------------------------------------------------------------


          Annual  sinking  fund  requirements  for the next  five  years are $30
million in 2002,  $13 million in each year 2003 and 2004, and $4 million in each
year 2005 and 2006.

(F)   SUBSIDIARY-OBLIGATED   MANDATORILY   REDEEMABLE  PREFERRED  SECURITIES  OF
      SUBSIDIARY TRUST OR LIMITED PARTNERSHIP  HOLDING SOLELY SUBORDINATED
      DEBENTURES OF SUBSIDIARIES-

          OE and CEI have each formed statutory  business trusts as wholly owned
financing  subsidiaries  for  which  they  own  all  of  the  respective  common
securities. Each trust sold preferred securities and invested the gross proceeds
in subordinated  debentures of the applicable parent company and the sole assets
of each trust are the applicable subordinated debentures. In each case, interest
payment provisions of the subordinated debentures match the distribution payment
provisions of the trust's preferred securities.  In addition, upon redemption or
payment at maturity of subordinated debentures, the applicable trust's preferred
securities  will be  redeemed  on a pro rata basis at their  liquidation  value.
Under certain  circumstances,  the applicable  subordinated  debentures could be
distributed to the holders of the outstanding  preferred securities of the trust
in the event that the trust is  liquidated.  The  applicable  parent company has
effectively  provided a full and unconditional  guarantee of payments due on its
trust's preferred  securities.  Their respective trust preferred  securities are
redeemable at 100% of their principal amount at the option of OE and,  beginning
in December 2006, at the option of CEI.

          Met-Ed and Penelec have each also formed statutory business trusts for
substantially  similar  transactions  as OE and CEI.  However,  ownership of the
respective  Met-Ed and Penelec trusts is through separate  wholly-owned  limited
partnerships,  of which a  wholly-owned  subsidiary  of each company is the sole
general partner. In these  transactions,  each trust invested the gross proceeds
from the sale of its trust preferred  securities in the preferred  securities of
the applicable limited partnership, which in turn invested those proceeds in the
7.35% and 7.34% subordinated debentures of Met-Ed and Penelec,  respectively. In
each case, the applicable parent company has effectively provided a full and

<PAGE>


unconditional   guarantee  of  its  obligations   under  its  trust's  preferred
securities.  The Met-Ed and Penelec trust preferred securities are redeemable at
the option of Met-Ed  and  Penelec  beginning  in May 2004 and  September  2004,
respectively, at 100% of their principal amount.

          Additionally,   JCP&L  has   formed  a  limited   partnership   for  a
substantially similar transaction; however, no statutory trust is involved. That
limited  partnership,  of which JCP&L is the sole general partner,  invested the
gross proceeds from the sale of its monthly income preferred  securities  (MIPS)
in JCP&L's 8.56% subordinated debentures.  JCP&L has effectively provided a full
and unconditional  guarantee of its obligations under its limited  partnership's
MIPS.  The limited  partnership's  MIPS are redeemable at the option of JCP&L at
100% of their principal  amount. In all of these  transactions,  interest on the
subordinated  debentures  (and therefore the  distributions  on trust  preferred
securities or MIPS) may be deferred for up to 60 months,  but the parent company
may not pay dividends on, or redeem or acquire,  any of its cumulative preferred
or common stock until deferred payments on its subordinated  debentures are paid
in full.

          The  following   table  lists  the   subsidiary   trusts  and  limited
partnership and information regarding their preferred securities  outstanding as
of December 31, 2001.

<TABLE>
<CAPTION>

-----------------------------------------------------------------------------------------
                                           Preferred Securities (a)
                                        ------------------------------
                                                                Stated       Subordinated
                                        Maturity     Rate        Value        Debentures
------------------------------------------------------------------------------------------
                                                                     (In millions)
<S>                                        <C>       <C>          <C>            <C>
Ohio Edison Financing Trust (b)......      2025      9.00%        $120.0         $123.7
Cleveland Electric Financing Trust (b)     2031      9.00%        $100.0         $103.1
Met-Ed Capital Trust (c).............      2039      7.35%        $100.0         $103.1
Penelec Capital Trust (c)............      2039      7.34%        $100.0         $103.1
JCP&L, Capital L.P. (b)..............      2044      8.56%        $125.0         $128.9
==========================================================================================

<FN>

(a)  The liquidation value is $25 per security.
(b)  The sole assets of the trust or limited partnership are the parent
     company's subordinated debentures with the same rate and maturity date as
     the preferred securities.
(c)  The sole assets of the trust are the preferred securities of Met-Ed Capital II, L.P. and Penelec
     Capital II, L.P., respectively, whose sole assets are the parent company's subordinated
     debentures with the same rate and maturity date as the preferred securities.

</FN>
</TABLE>


     (G) LONG-TERM DEBT-

          The first mortgage indentures and their supplements,  which secure all
of the Companies' first mortgage bonds,  serve as direct first mortgage liens on
substantially  all property and  franchises,  other than  specifically  excepted
property, owned by the Companies.

          Based on the amount of bonds  authenticated  by the  Trustees  through
December  31,  2001,  the  Companies'   annual  sinking  and  improvement   fund
requirements for all bonds issued under the mortgages  amounts to $66.9 million.
OE, TE and Penn expect to deposit funds in 2002 that will be withdrawn  upon the
surrender  for  cancellation  of a like  principal  amount of  bonds,  which are
specifically authenticated for such purposes against unfunded property additions
or against  previously  retired bonds. This method can result in minor increases
in the amount of the annual sinking fund requirement.  JCP&L, Met-Ed and Penelec
expect to fulfill their  sinking and  improvement  fund  obligation by providing
bondable  property  additions  and/or retired bonds to the Trustee to meet their
annual sinking fund requirement.

          Sinking  fund  requirements  for first  mortgage  bonds  and  maturing
long-term  debt  (excluding  capital  leases  and  long-term  debt  included  in
"Liabilities Related to Assets Pending Sale") for the next five years are:

                              (In millions)
          ---------------------------------
            2002..............  $1,654.7
            2003..............     928.1
            2004..............   1,421.1
            2005..............     853.3
            2006..............   1,432.5
          ---------------------------------

          The Companies'  obligations to repay certain pollution control revenue
bonds are secured by several series of first mortgage bonds.  Certain  pollution
control revenue bonds are entitled to the benefit of irrevocable bank letters of
credit of $287.6 million and noncancelable  municipal bond insurance policies of
$493.9  million to pay  principal  of, or  interest  on, the  pollution  control
revenue bonds. To the extent that drawings are made under the letters of credit,
the Companies are entitled to a credit  against their  obligation to repay those
bonds.  The  Companies  pay annual fees of 1.00% to 1.375% of the amounts of the
letters of credit to the issuing  banks and are obligated to reimburse the banks
for any drawings thereunder.


<PAGE>

          FirstEnergy  had  unsecured  borrowings of $250 million as of December
31,  2001, supported  by a $500  million  long-term  revolving  credit  facility
agreement which expires November 29, 2004. As of December 31, 2001,  FirstEnergy
currently  pays an annual  facility  fee of 0.25% on the total  credit  facility
amount.  The fee is  subject  to  change  based on  credit  agency  ratings  for
FirstEnergy.

          OE had no  unsecured  borrowings  as of December 31, 2001 under a $250
million long-term revolving credit facility agreement which expires November 18,
2002. OE must pay an annual  facility fee of 0.20% on the total credit  facility
amount. In addition, the credit agreement provides that OE maintain unused first
mortgage  bond  capability  for the full  credit  agreement  amount  under  OE's
indenture as potential security for the unsecured borrowings.

          CEI and TE have  letters of credit of  approximately  $222  million in
connection  with the sale and  leaseback of Beaver  Valley Unit 2 that expire in
May 2002.  The letters of credit are secured by first  mortgage bonds of CEI and
TE in the proportion of 40% and 60%, respectively (see Note 3).

          OE's and Penn's  nuclear  fuel  purchases  are  financed  through  the
issuance of OES Fuel commercial paper and loans,  both of which are supported by
a $141.5 million  long-term bank credit  agreement which expires March 31, 2002.
FirstEnergy does not anticipate extending the credit agreement. Accordingly, the
commercial paper and loans are reflected as currently  payable long-term debt on
the December 31, 2001  Consolidated  Balance Sheet.  OES Fuel must pay an annual
facility fee of 0.20% on the total line of credit and an annual  commitment  fee
of 0.0625% on any unused amount.

     (H) COMPREHENSIVE INCOME-

          Comprehensive   income   includes   net  income  as  reported  on  the
Consolidated  Statements of Income and all other changes in common stockholders'
equity except those resulting from transactions with common stockholders.  As of
December 31, 2001,  accumulated other comprehensive income (loss) consisted of a
minimum liability for unfunded retirement  benefits of $0.6 million,  unrealized
gains on  investments  in  securities  available  for sale of $1.0  million  and
unrealized losses on derivative instrument hedges of $169.4 million.

5.   SHORT-TERM BORROWINGS AND BANK LINES OF CREDIT:

          Short-term  borrowings  outstanding as of December 31, 2001, consisted
of  $688.3  million  of bank  borrowings  and  $159.8  million  of OES  Capital,
Incorporated  commercial paper.  Total borrowings include $233.8 million related
to pending  divestitures (see Note 2 - Merger) that are included in "Liabilities
Related to Assets Pending Sale" on the Consolidated Balance Sheet as of December
31, 2001.  OES Capital is a wholly owned  subsidiary of OE whose  borrowings are
secured by  customer  accounts  receivable.  OES  Capital  can borrow up to $170
million under a receivables  financing  agreement at rates based on certain bank
commercial  paper and is required to pay an annual fee of 0.20% on the amount of
the entire finance limit. The receivables financing agreement expires in 2002.

          FirstEnergy  and  its  subsidiaries  have  various  credit  facilities
(including a FirstEnergy $1 billion  short-term  revolving credit facility) with
domestic and foreign banks that provide for  borrowings of up to $1.291  billion
under various  interest rate options.  OE's  short-term  borrowings  may be made
under its lines of credit on its unsecured  notes. To assure the availability of
these  lines,  FirstEnergy  and its  subsidiaries  are  required  to pay  annual
commitment  fees that vary from 0.125% to 0.20%.  These lines  expire at various
times during 2002. The weighted average interest rates on short-term  borrowings
outstanding   as  of  December  31,  2001  and  2000,   were  3.80%  and  7.92%,
respectively.

6.   COMMITMENTS, GUARANTEES AND CONTINGENCIES:

       CAPITAL EXPENDITURES-

          FirstEnergy's  current forecast reflects expenditures of approximately
$3.4 billion for property  additions and improvements  from 2002-2006,  of which
approximately  $850 million is applicable to 2002.  Investments  for  additional
nuclear fuel during the 2002-2006 period are estimated to be approximately  $536
million,  of which  approximately  $54 million applies to 2002.  During the same
periods,  the Companies'  nuclear fuel investments are expected to be reduced by
approximately $507 million and $101 million,  respectively,  as the nuclear fuel
is consumed.

       STOCK REPURCHASE PROGRAM-

          On November 17, 1998, the Board of Directors authorized the repurchase
of up to 15 million  shares of  FirstEnergy's  common  stock  over a  three-year
period  beginning  in  1999.  Repurchases  were  made  on the  open  market,  at
prevailing  prices,  and were funded primarily through the use of operating cash
flows. During 2001, 2000 and 1999,  FirstEnergy  repurchased and retired 550,000
shares (average price of $27.82 per share), 7.9 million shares (average price of
$24.51 per share) and 4.6 million  shares  (average  price of $28.08 per share),
respectively.


<PAGE>


       NUCLEAR INSURANCE-

          The  Price-Anderson  Act  limits the public  liability  relative  to a
single incident at a nuclear power plant to $9.5 billion.  The amount is covered
by a combination of private insurance and an industry retrospective rating plan.
The Companies'  maximum  potential  assessment under the industry  retrospective
rating plan would be $352.4  million per  incident but not more than $40 million
in any one year for each incident.

          The Companies are also insured under  policies for each nuclear plant.
Under these  policies,  up to $2.75 billion is provided for property  damage and
decontamination  and  decommissioning  costs.  The Companies  have also obtained
approximately  $1.2 billion of insurance  coverage for replacement  power costs.
Under these policies,  the Companies can be assessed a maximum of  approximately
$71 million for incidents at any covered  nuclear  facility  occurring  during a
policy year which are in excess of  accumulated  funds  available to the insurer
for paying losses.

          The Companies  intend to maintain  insurance  against nuclear risks as
described  above as long as it is  available.  To the  extent  that  replacement
power, property damage, decontamination, decommissioning, repair and replacement
costs  and other  such  costs  arising  from a  nuclear  incident  at any of the
Companies'  plants  exceed the policy  limits of the  insurance  in effect  with
respect to that plant, to the extent a nuclear  incident is determined not to be
covered by the Companies'  insurance  policies,  or to the extent such insurance
becomes  unavailable in the future,  the Companies would remain at risk for such
costs.

       ENVIRONMENTAL MATTERS-

          Various federal,  state and local  authorities  regulate the Companies
with  regard  to  air  and  water  quality  and  other  environmental   matters.
FirstEnergy   estimates   additional  capital   expenditures  for  environmental
compliance of approximately $225 million,  which is included in the construction
forecast provided under "Capital Expenditures" for 2002 through 2006.

          The Companies are required to meet federally  approved  sulfur dioxide
(SO2) regulations.  Violations of such regulations can result in shutdown of the
generating unit involved and/or civil or criminal penalties of up to $27,500 for
each day the unit is in violation. The Environmental Protection Agency (EPA) has
an  interim  enforcement  policy  for SO2  regulations  in Ohio that  allows for
compliance based on a 30-day averaging period. The Companies cannot predict what
action the EPA may take in the future with  respect to the  interim  enforcement
policy.

          The  Companies  are in  compliance  with the current SO2 and  nitrogen
oxide (NOx) reduction  requirements under the Clean Air Act Amendments of 1990.
SO2 reductions are being achieved by burning lower-sulfur fuel,  generating more
electricity from lower-emitting  plants,  and/or using emission allowances.  NOx
reductions are being achieved through combustion  controls and the generation of
more electricity at lower-emitting  plants. In September 1998, the EPA finalized
regulations  requiring  additional NOx reductions  from the Companies'  Ohio and
Pennsylvania facilities. The EPA's NOx Transport Rule imposes uniform reductions
of NOx  emissions (an  approximate  85% reduction in utility plant NOx emissions
from  projected  2007  emissions)  across a region of  nineteen  states  and the
District of Columbia,  including New Jersey,  Ohio and Pennsylvania,  based on a
conclusion  that such NOx  emissions  are  contributing  significantly  to ozone
pollution in the eastern United States.  State  Implementation  Plans (SIP) must
comply by May 31, 2004 with individual state NOx budgets established by the EPA.
Pennsylvania  submitted a SIP that requires  compliance  with the NOx budgets at
the  Companies'  Pennsylvania  facilities  by May 1, 2003 and Ohio  submitted  a
"draft" SIP that requires compliance with the NOx budgets at the Companies' Ohio
facilities by May 31, 2004. The Companies  continue to evaluate their compliance
plans and other compliance options.

          In July 1997, the EPA promulgated  changes in the National Ambient Air
Quality  Standard  (NAAQS)  for ozone  emissions  and  proposed  a new NAAQS for
previously  unregulated  ultra-fine  particulate  matter.  In May 1999, the U.S.
Court of Appeals found  constitutional and other defects in the new NAAQS rules.
In February 2001, the U.S.  Supreme Court upheld the new NAAQS rules  regulating
ultra-fine  particulates  but found defects in the new NAAQS rules for ozone and
decided that the EPA must revise those rules. The future cost of compliance with
these  regulations  may be  substantial  and  will  depend  if and how  they are
ultimately  implemented  by the states in which the Companies  operate  affected
facilities.

          In 1999 and 2000,  the EPA  issued  Notices  of  Violation  (NOV) or a
Compliance Order to nine utilities covering 44 power plants, including the W. H.
Sammis  Plant.  In addition,  the U.S.  Department  of Justice filed eight civil
complaints against various investor-owned utilities,  which included a complaint
against OE and Penn in the U.S.  District  Court for the  Southern  District  of
Ohio.  The NOV and  complaint  allege  violations  of the Clean Air Act based on
operation and maintenance of the Sammis Plant dating back to 1984. The complaint
requests  permanent  injunctive  relief to  require  the  installation  of "best
available  control  technology"  and civil penalties of up to $27,500 per day of
violation.  Although  unable  to  predict  the  outcome  of  these  proceedings,
FirstEnergy  believes the Sammis Plant is in full  compliance with the Clean Air
Act and the NOV and complaint are without merit.  Penalties  could be imposed if
the Sammis Plant continues to


<PAGE>

operate without  correcting the alleged  violations and a court  determines that
the  allegations  are valid.  The Sammis Plant  continues to operate while these
proceedings are pending.

          In  December  2000,  the EPA  announced  it  would  proceed  with  the
development of  regulations  regarding  hazardous air  pollutants  from electric
power  plants.  The EPA  identified  mercury as the  hazardous  air pollutant of
greatest  concern.  The EPA  established  a schedule to propose  regulations  by
December 2003 and issue final  regulations  by December 2004. The future cost of
compliance with these regulations may be substantial.

          As a result of the Resource  Conservation and Recovery Act of 1976, as
amended,  and the  Toxic  Substances  Control  Act of 1976,  federal  and  state
hazardous  waste   regulations  have  been  promulgated.   Certain   fossil-fuel
combustion waste products,  such as coal ash, were exempted from hazardous waste
disposal  requirements  pending  the  EPA's  evaluation  of the need for  future
regulation.   The  EPA  has  issued  its  final  regulatory  determination  that
regulation of coal ash as a hazardous waste is  unnecessary.  In April 2000, the
EPA announced that it will develop  national  standards  regulating  disposal of
coal ash under its authority to regulate nonhazardous waste.

          Various   environmental   liabilities  have  been  recognized  on  the
Consolidated  Balance  Sheet as of December 31, 2001,  based on estimates of the
total costs of cleanup,  the Companies'  proportionate  responsibility  for such
costs and the  financial  ability of other  nonaffiliated  entities to pay.  The
Companies have been named as "potentially  responsible  parties" (PRPs) at waste
disposal sites which may require cleanup under the  Comprehensive  Environmental
Response,  Compensation  and Liability Act of 1980.  Allegations  of disposal of
hazardous  substances at historical  sites and the liability  involved are often
unsubstantiated and subject to dispute. Federal law provides that all PRPs for a
particular site be held liable on a joint and several basis. In addition,  JCP&L
has accrued liabilities for environmental remediation of former manufactured gas
plants  in New  Jersey;  those  costs  are being  recovered  by JCP&L  through a
non-bypassable  societal  benefits  charge.  The  Companies  have total  accrued
liabilities  aggregating  approximately  $60  million as of December  31,  2001.
FirstEnergy  does  not  believe  environmental  remediation  costs  will  have a
material  adverse  effect on its financial  condition,  cash flows or results of
operations.

       OTHER LEGAL PROCEEDINGS-

           Various lawsuits, claims and proceedings related to FirstEnergy's
normal business operations are pending against FirstEnergy and its subsidiaries.
The most significant are described below.

          Unit 2 of the Three Mile Island  Nuclear Plant (TMI-2) was acquired by
FirstEnergy  in 2001 as part of the  merger  with  GPU.  As a result of the 1979
TMI-2  accident,  claims for alleged  personal  injury  against  JCP&L,  Met-Ed,
Penelec and GPU were filed in the U.S. District Court for the Middle District of
Pennsylvania.  In 1996, the District Court granted a motion for summary judgment
filed by GPU and  dismissed the ten initial "test cases" which had been selected
for a test case trial, as well as all of the remaining 2,100 pending claims.  In
November  1999,  the U.S.  Court of Appeals for the Third  Circuit  affirmed the
District Court's  dismissal of the ten "test cases," but set aside the dismissal
of the  additional  pending  claims,  remanding  them to the District  Court for
further proceedings.  In September 2000, GPU filed for a summary judgment in the
District Court.  Meanwhile,  the plaintiffs  appealed to the Third Circuit for a
review of the District  Court's  decision  placing  limitations on the remaining
plaintiffs'  suits.  In April 2001,  the Third  Circuit  affirmed  the  District
Court's decision. In July 2001, GPU renewed its motion for a summary judgment on
the  remaining  2,100 claims in the  District  Court.  On January 15, 2002,  the
District  Court granted GPU's amended motion for summary  judgment.  On February
14,  2002  plaintiffs  filed a notice of appeal to the  United  States  Court of
Appeals for the Third Circuit. In addition to the approximately 2,100 claims for
which  summary  judgment has been  granted,  there is other  pending  litigation
arising out of the TMI-2 accident.  This  litigation  consists of the following:
eight personal injury cases that were not consolidated with the above-referenced
approximately  2,100 claims;  two class actions  brought on behalf of plaintiffs
alleging additional injuries diagnosed after the filing of the complaints in the
above-referenced case; a case alleging exposure during the post-accident cleanup
of the TMI-2  plant;  and claims by  individual  businesses  for  economic  loss
resulting  from the TMI-2  accident.  Although  unable to predict the outcome of
this  litigation,  FirstEnergy  believes that any liability to which it might be
subject by reason of the TMI-2 accident will not exceed its financial protection
under the Price-Anderson Act.

          In July 1999, the Mid-Atlantic  states experienced a severe heat storm
which  resulted in power  outages  throughout  the service  territories  of many
electric  utilities,  including the territory of JCP&L. In an investigation into
the  causes  of  the  outages  and  the  reliability  of  the  transmission  and
distribution  systems  of all four New  Jersey  electric  utilities,  the  NJBPU
concluded  that there was not a prima facie case  demonstrating  that,  overall,
JCP&L provided  unsafe,  inadequate or improper  service to its  customers.  Two
class action lawsuits (subsequently  consolidated into a single proceeding) were
filed in New Jersey Superior Court in July 1999 against JCP&L, GPU and other GPU
companies  seeking  compensatory and punitive damages arising from the July 1999
service  interruptions  in the JCP&L  territory.  In May 2001,  the court denied
without prejudice the defendants'  motion seeking  decertification of the class.
Discovery  continues  in the class  action,  but no trial date has been set. The
judge has set a schedule under which factual legal  discovery  would conclude in
March 2002, and expert reports would be exchanged by June 2002. In October 2001,
the court held argument on the plaintiffs'  motion for partial summary judgment,
which   contends  that  JCP&L  is  bound  to  several   findings  of  the  NJBPU
investigation.  The plaintiffs'  motion was denied by the Court in November 2001
and the

<PAGE>


plaintiffs'  motion  to file an appeal of this  decision  was  denied by the New
Jersey  Appellate  Division.  JCP&L has also filed a motion for partial summary
judgement that is currently  pending before the Superior  Court.  FirstEnergy is
unable to predict the outcome of these matters.

OTHER  COMMITMENTS,  GUARANTEES AND CONTINGENCIES-

          GPU  had  made  significant  investments  in  foreign  businesses  and
facilities  through  its GPU  Electric  and  GPU  Power  subsidiaries.  Although
FirstEnergy  will attempt to mitigate its risks related to foreign  investments,
it faces  additional  risks inherent in operating in such  locations,  including
foreign currency fluctuations.

          GPU  Electric,  through  its  subsidiary,  Midlands,  has a 40% equity
interest in a 586 MW power  project in Pakistan (the Uch Power  Project),  which
commenced  commercial  operations in October 2000. GPU Electric's  investment in
this  project as of December  31, 2001 was  approximately  $38  million,  plus a
guaranty  letter  of  credit of $3.6  million,  and its  share of the  projected
completion costs represents an additional $4.8 million commitment.  Cinergy (the
former  owner  of 50% of  Midlands  Electricity  plc)  agreed  to  fund up to an
aggregate of $20 million of the required capital contributions,  for a period of
one year from July 15, 1999,  and "cash  losses"  which could be incurred on the
Uch Power Project,  for a period of up to ten years from July 15, 1999.  Cinergy
has reimbursed GPU Electric $4.9 million  through  December 31, 2001,  leaving a
remaining  commitment  for future cash losses of up to $15.1  million.  Midlands
also has a 31% equity  interest in a 478 MW power  project in Turkey (the Trakya
Power Project).  Trakya is presently  engaged in a foreign  currency  conversion
issue with TETTAS (the state owned electricity purchaser).  Midlands established
a $16.5 million reserve for  non-recovery  relating to that issue as of December
31, 2001.  These  commitments  and  contingencies  associated with Midlands will
transfer to the new partnership  upon completion of the sale discussed in Note 2
-  Merger,  with  FirstEnergy  being  responsible  for its  lower  proportionate
interest.

          EI Barranquilla,  a wholly owned subsidiary of GPU Power, is an equity
investor in Termobarranquilla S.A., Empresa de Servicios Publicos (TEBSA), which
owns a Colombian  independent power generation project. As of December 31, 2001,
GPU Power has an  investment  of  approximately  $109.4  million in TEBSA and is
committed,  under  certain  circumstances,  to make  additional  standby  equity
contributions  of $21.3 million,  which  FirstEnergy has  guaranteed.  The total
outstanding  senior debt of the TEBSA  project is $315  million at December  31,
2001. The lenders include the Overseas Private Investment Corporation, US Export
Import Bank and a commercial bank syndicate.  GPU had guaranteed the obligations
of the operators of the TEBSA project,  up to a maximum of $5.8 million (subject
to escalation) under the project's operations and maintenance agreement.

          GPU believed that various  events of default have  occurred  under the
loan agreements relating to the TEBSA project. In addition,  questions have been
raised as to the accuracy and  completeness  of information  provided to various
parties to the project in connection with the project's  formation.  FirstEnergy
continues to discuss these issues and related matters with the project  lenders,
CORELCA  (the  government  owned  Colombian  electric  utility with an ownership
interest in the project) and the Government of Colombia.

          Moreover,  in September  2001,  the DIAN (the  Colombian  national tax
authority) had presented TEBSA with a statement of charges alleging that certain
lease payments made under the Lease  Agreement  with Los Amigos Leasing  Company
(an indirect wholly owned  subsidiary of GPU Power) violated  Colombian  foreign
exchange regulations and were, therefore,  subject to substantial penalties. The
DIAN has calculated a statutory penalty amounting to approximately  $200 million
and gave TEBSA two months to respond to the  statement  of charges.  In November
2001,  TEBSA filed a formal  response  to this  statement  of charges.  TEBSA is
continuing  to review the DIAN's  position and has been advised by its Colombian
counsel that the DIAN's position is without substantial legal merit. FirstEnergy
is unable to predict the outcome of these matters.

7.   SEGMENT INFORMATION:

          FirstEnergy   operates  under  the  following   reportable   segments:
regulated services,  competitive services and other (primarily corporate support
services and international operations acquired in the GPU merger). FirstEnergy's
primary segment is its regulated services,  which include eight electric utility
operating companies in Ohio,  Pennsylvania and New Jersey that formerly provided
bundled electric  service.  Its other material  business segment consists of the
subsidiaries that operate unregulated energy and energy-related businesses.

          The  regulated  services  segment  designs,  constructs,  operates and
maintains FirstEnergy's regulated transmission and distribution systems. It also
provides  generation  services to  regulated  franchise  customers  who have not
chosen an alternative,  competitive  generation supplier. The regulated services
segment  obtains a portion  of its  required  generation  through  power  supply
agreements with the competitive services segment.

<PAGE>


          The competitive  services  segment  includes all domestic  unregulated
energy and energy-related  services including  commodity sales (both electricity
and natural gas) in the retail and wholesale markets, marketing,  generation and
sourcing   of   commodity   requirements,   as   well   as   other   competitive
energy-application  services.  Competitive products are increasingly marketed to
customers as bundled services.

          2000 and 1999  financial  data are pro forma amounts to represent 2001
business segment organizations and operations. Financial data for these business
segments are as follows:

<TABLE>
<CAPTION>


     Segment Financial Information
     -----------------------------

                                           Regulated      Competitive                Reconciling
                                            Services        Services       Other     Adjustments     Consolidated
                                           ---------      -----------      -----     -----------     ------------
                                                                        (In millions)
<S>                                         <C>             <C>           <C>         <C>               <C>
       2001
       ----
External revenues.....................      $ 5,729         $2,165        $   11      $    94 (a)       $ 7,999
Internal revenues.....................        1,480          2,011           350       (3,841)(b)            --
   Total revenues.....................        7,209          4,176           361       (3,747)            7,999
Depreciation and amortization.........          841             21            28           --               890
Net interest charges..................          571             25            74         (114)(b)           556
Income taxes..........................          469             45           (40)          --               474
Income before cumulative effect of a
   change in accounting...............          640             66           (51)          --               655
Net income............................          640             57           (51)          --               646
Total assets..........................       28,054          2,981         6,317           --            37,352
Property additions....................          447            375            30           --               852

       2000
       ----
External revenues.....................      $ 5,415         $1,545        $    1      $    68 (a)       $ 7,029
Internal revenues.....................        1,364          2,280           306       (3,950)(b)            --
   Total revenues.....................        6,779          3,825           307       (3,882)            7,029
Depreciation and amortization.........          919             13             2           --               934
Net interest charges..................          558             10            19          (58)(b)           529
Income taxes..........................          297             95           (15)          --               377
Net income............................          465            137            (3)          --               599
Total assets..........................       14,682          2,685           574           --            17,941
Property additions....................          422            126            40           --               588

       1999
       ----
External revenues.....................      $ 5,448         $  796        $   60      $    16 (a)       $ 6,320
Internal revenues.....................        1,274          2,240           184       (3,698)(b)            --
   Total revenues.....................        6,722          3,036           244       (3,682)            6,320
Depreciation and amortization.........          928             10            --           --               938
Net interest charges..................          613              8             6          (55)(b)           572
Income taxes..........................          288             90            17           --               395
Net income............................          414            129            25           --               568
Total assets..........................       16,792          1,030           402           --            18,224
Property additions....................          418            207            --           --               625


<FN>

Reconciling adjustments to segment operating results from internal management
reporting to consolidated external financial reporting:

(a)  Principally fuel marketing revenues which are reflected as reductions to expenses for internal management reporting purposes.
(b)  Elimination of intersegment transactions.


</FN>
</TABLE>

     Products and Services
     ---------------------
                                                    Energy Related
                  Electricity      Oil & Gas          Sales and
   Year              Sales           Sales             Services
   ----           -----------      ---------        --------------
                                  (In millions)
   2001             $6,078            $792                $693
   2000              5,537             582                 563
   1999              5,253             203                 503


     2001 Geographic Information    Revenues           Assets
     ---------------------------    --------          ------
                                          (In millions)
     United States...............      $7,991          $32,187
     Foreign countries*..........           8            5,165
                                       ------          -------
       Total.....................      $7,999          $37,352

    * See Note 2 for discussion of planned divestitures of international
      operations.


<PAGE>
<TABLE>
<CAPTION>


8.   SUMMARY OF QUARTERLY FINANCIAL DATA (UNAUDITED):


The following summarizes certain consolidated operating results by quarter for
2001 and 2000.

                                                 March 31,         June 30,      September 30,     December 31,
      Three Months Ended                           2001              2001           2001              2001(a)
----------------------------------------------------------------------------------------------------------------
                                                              (In millions, except per share amounts)

<S>                                              <C>               <C>             <C>               <C>
Revenues.......................................  $1,985.7          $1,804.1        $1,951.6          $2,257.9
Expenses.......................................   1,669.4           1,416.7         1,412.1           1,816.0
----------------------------------------------------------------------------------------------------------------
Income Before Interest and Income Taxes........     316.3             387.4           539.5             441.9
Net Interest Charges...........................     126.3             121.0           124.1             184.3
Income Taxes...................................      83.8             120.4           181.3              89.0
----------------------------------------------------------------------------------------------------------------
Income Before
   Cumulative Effect of Accounting Change......     106.2             146.0           234.1             168.6
Cumulative Effect of Accounting Change
   (Net of Income Taxes) (Note 1)..............      (8.5)             --              --                --
----------------------------------------------------------------------------------------------------------------
Net Income.....................................  $   97.7          $  146.0        $  234.1          $  168.6
================================================================================================================
Basic Earnings Per Share of Common Stock:
   Before Cumulative Effect of Accounting Change $    .49          $    .67        $   1.07          $    .64
   Cumulative Effect of Accounting Change
     (Net of Income Taxes) (Note 1)............      (.04)             --              --                --
----------------------------------------------------------------------------------------------------------------
Basic Earnings Per Share of Common Stock.......  $    .45          $    .67        $   1.07          $    .64
----------------------------------------------------------------------------------------------------------------
Diluted Earnings Per Share of Common Stock:
   Before Cumulative Effect of Accounting Change $    .49          $    .67        $   1.06          $    .64
   Cumulative Effect of Accounting Change
     (Net of Income Taxes) (Note 1)............      (.04)             --              --                --
----------------------------------------------------------------------------------------------------------------
Diluted Earnings Per Share of Common Stock.....  $    .45          $    .67        $   1.06          $    .64
================================================================================================================

<FN>

(a) Results for the former GPU companies are included from the November 7, 2001
acquisition date through December 31, 2001.

</FN>
</TABLE>


<TABLE>
<CAPTION>

                                                 March 31,         June 30,      September 30,     December 31,
      Three Months Ended                           2000              2000           2000              2000
----------------------------------------------------------------------------------------------------------------
                                                              (In millions, except per share amounts)

<S>                                              <C>               <C>             <C>               <C>
Revenues.......................................  $1,607.9          $1,702.1        $1,891.7          $1,827.3
Expenses....................................      1,234.1           1,338.0         1,433.1           1,518.9
----------------------------------------------------------------------------------------------------------------
Income Before Interest and Income Taxes........     373.8             364.1           458.6             308.4
Net Interest Charges...........................     135.0             134.4           131.2             128.5
Income Taxes...................................      97.9              95.1           129.2              54.6
----------------------------------------------------------------------------------------------------------------
Net Income.....................................  $  140.9          $  134.6        $  198.2          $  125.3
================================================================================================================
Basic and Diluted Earnings per Share of
   Common Stock................................  $    .63          $    .60        $    .89          $    .57
================================================================================================================


</TABLE>


9.   PRO FORMA COMBINED CONDENSED FIRSTENERGY STATEMENTS OF INCOME (UNAUDITED):

          The following  pro forma  combined  condensed  statements of income of
FirstEnergy  give  effect  to  the  FirstEnergy/GPU  merger  as if it  had  been
consummated  on  January  1,  2000,  with the  purchase  accounting  adjustments
actually recognized in the business  combination (see Note 2 - Merger).  The pro
forma combined condensed financial  statements have been prepared to reflect the
merger under the purchase method of accounting with  FirstEnergy  acquiring GPU.
Under the purchase method of accounting,  tangible and  identifiable  intangible
assets  acquired and  liabilities  assumed are recorded at their  estimated fair
values. The excess of the purchase price,  including estimated fees and expenses
related to the merger,  over the net assets acquired  (which  included  existing
goodwill  of  $1.9  billion)  is  classified  as  goodwill  and  amounts  to an
additional  $2.3  billion.  In  addition,  the pro forma  adjustments  reflect a
reduction  in  debt  from  application  of the  proceeds  from  certain  pending
divestitures as well as the related reduction in interest costs.

                                                Year Ended December 31,
                                                -----------------------
                                                2001               2000
                                                ----               ----
                                        (In millions, except per share amounts)

Revenues.................................     $12,108             $11,703
Expenses.................................       9,768               9,377
-------------------------------------------------------------------------
Income Before Interest and Income Taxes..       2,340               2,326
Net Interest Charges.....................         941                 977
Income Taxes.............................         561                 527
-------------------------------------------------------------------------
Net Income...............................     $   838             $   822
-------------------------------------------------------------------------
Earnings per Share of Common Stock.......     $  2.87             $  2.77
-------------------------------------------------------------------------


<PAGE>